FirstEnergy FactBook
Published May 1, 2015
Creating Value for Investors
Company Profile
FirstEnergy FactBook
Forward-Looking Statement
Published May 1, 2015
1
All information contained in this FactBook is as of
May 1, 2015 unless otherwise noted.
This FactBook includes forward-looking statements based on information currently available to management. Such statements are subject to certain risks and uncertainties. These
statements include declarations regarding management's intents, beliefs and current expectations. These statements typically contain, but are not limited to, the terms “anticipate,”
“potential,” “expect,” "forecast," “target”, "will," "intend," “believe,” "project," “estimate" and similar words. Forward-looking statements involve estimates, assumptions, known and
unknown risks, uncertainties and other factors that may cause actual results, performance or achievements to be materially different from any future results, performance or achievements
expressed or implied by such forward-looking statements, which may include the following: the speed and nature of increased competition in the electric utility industry, in general, and the
retail sales market in particular; the ability to experience growth in the Regulated Distribution and Regulated Transmission segments and to successfully implement our revised sales
strategy for the Competitive Energy Services segment; the accomplishment of our regulatory and operational goals in connection with our transmission investment plan, pending
transmission rate case and the effectiveness of our repositioning strategy to reflect a more regulated business profile; changes in assumptions regarding economic conditions within our
territories, assessment of the reliability of our transmission system, or the availability of capital or other resources supporting identified transmission investment opportunities; the impact of
the regulatory process on the pending matters at the federal level and in the various states in which we do business including, but not limited to, matters related to rates and the Electric
Security Plan IV in Ohio; the impact of the federal regulatory process on the Federal Energy Regulatory Commission (FERC)-regulated entities and transactions, in particular FERC regulation
of wholesale energy and capacity markets, including PJM Interconnection, L.L.C. (PJM) markets and FERC-jurisdictional wholesale transactions; FERC regulation of cost-of-service rates,
including FERC Opinion No. 531's revised Return on Equity methodology for FERC jurisdictional wholesale generation and transmission utility service; and FERC’s compliance and
enforcement activity, including compliance and enforcement activity related to North American Electric Reliability Corporation’s mandatory reliability standards; the uncertainties of various
cost recovery and cost allocation issues resulting from American Transmission Systems Incorporated's realignment into PJM; economic or weather conditions affecting future sales and
margins such as a polar vortex or other significant weather events, and all associated regulatory events or actions; changing energy, capacity and commodity market prices including, but
not limited to, coal, natural gas and oil, and their availability and impact on retail margins; the continued ability of our regulated utilities to recover their costs; costs being higher than
anticipated and the success of our policies to control costs and to mitigate low energy, capacity and market prices; other legislative and regulatory changes, and revised environmental
requirements, including, but not limited to, proposed greenhouse gases emission and water discharge regulations and the effects of the United States Environmental Protection Agency's
coal combustion residuals regulations, Cross-State Air Pollution Rule, Mercury and Air Toxics Standards, including our estimated costs of compliance, and Clean Water Act 316(b) water
intake regulation; the uncertainty of the timing and amounts of the capital expenditures that may arise in connection with any litigation, including New Source Review litigation, or potential
regulatory initiatives or rulemakings (including that such initiatives or rulemakings could result in our decision to deactivate or idle certain generating units); the uncertainties associated
with the deactivation of certain older regulated and competitive fossil units, including the impact on vendor commitments, and the timing thereof as they relate to the reliability of the
transmission grid; the impact of other future changes to the operational status or availability of our generating units; adverse regulatory or legal decisions and outcomes with respect to our
nuclear operations (including, but not limited to the revocation or non-renewal of necessary licenses, approvals or operating permits by the Nuclear Regulatory Commission or as a result of
the incident at Japan's Fukushima Daiichi Nuclear Plant); issues arising from the indications of cracking in the shield building at Davis-Besse; the risks and uncertainties associated with
litigation, arbitration, mediation and like proceedings, including, but not limited to, any such proceedings related to vendor commitments; the impact of labor disruptions by our unionized
workforce; replacement power costs being higher than anticipated or not fully hedged; the ability to comply with applicable state and federal reliability standards and energy efficiency and
peak demand reduction mandates; changes in customers' demand for power, including, but not limited to, changes resulting from the implementation of state and federal energy efficiency
and peak demand reduction mandates; the ability to accomplish or realize anticipated benefits from strategic and financial goals, including, but not limited to, the ability to continue to
reduce costs and to successfully execute our financial plans designed to improve our credit metrics and strengthen our balance sheet through, among other actions, our previouslyimplemented dividend reduction, our cash flow initiative project and our other proposed capital raising initiatives; our ability to improve electric commodity margins and the impact of,
among other factors, the increased cost of fuel and fuel transportation on such margins; changing market conditions that could affect the measurement of certain liabilities and the value of
assets held in our Nuclear Decommissioning Trusts, pension trusts and other trust funds, and cause us and/or our subsidiaries to make additional contributions sooner, or in amounts that
are larger than currently anticipated; the impact of changes to material accounting policies; the ability to access the public securities and other capital and credit markets in accordance with
our announced financial plans, the cost of such capital and overall condition of the capital and credit markets affecting us and our subsidiaries; actions that may be taken by credit rating
agencies that could negatively affect us and/or our subsidiaries' access to financing, increase the costs thereof, and increase requirements to post additional collateral to support
outstanding commodity positions, letters of credit and other financial guarantees; changes in national and regional economic conditions affecting us, our subsidiaries and/or our major
industrial and commercial customers, and other counterparties with which we do business, including fuel suppliers; the impact of any changes in tax laws or regulations or adverse tax audit
results or rulings; issues concerning the stability of domestic and foreign financial institutions and counterparties with which we do business; the risks associated with cyber-attacks on our
electronic data centers that could compromise the information stored on our networks, including proprietary information and customer data; and the risks and other factors discussed from
time to time in our United States Securities and Exchange Commission filings, and other similar factors. Dividends declared from time to time on FirstEnergy Corp.'s common stock during
any period may in the aggregate vary from prior periods due to circumstances considered by FirstEnergy Corp.'s Board of Directors at the time of the actual declarations. A security rating is
not a recommendation to buy or hold securities and is subject to revision or withdrawal at any time by the assigning rating agency. Each rating should be evaluated independently of any
other rating. The foregoing review of factors should not be construed as exhaustive. New factors emerge from time to time, and it is not possible for management to predict all such factors,
nor assess the impact of any such factor on FirstEnergy's business or the extent to which any factor, or combination of factors, may cause results to differ materially from those contained in
any forward-looking statements. FirstEnergy expressly disclaims any current intention to update, except as required by law, any forward-looking statements contained herein as a result of
new information, future events or otherwise.
FirstEnergy FactBook
Published May 1, 2015
2
1
FirstEnergy FactBook
Published May 1, 2015
Non-GAAP Financial Matters
All information contained in this FactBook is as of
May 1, 2015 unless otherwise noted.
This FactBook contains references to non-GAAP financial measures including, among others, Operating earnings, Adjusted EBITDA,
Adjusted Debt, Adjusted Capitalization, Funds from Operations (FFO) and Free Cash Flow. In addition, Basic EPS and Basic EPSOperating, each calculated on a segment basis, are also non-GAAP financial measures. Generally, a non-GAAP financial measure is a
numerical measure of a company’s historical or future financial performance, financial position, or cash flows that either excludes or
includes amounts that are not normally excluded or included in the most directly comparable measure calculated and presented in
accordance with accounting principles generally accepted in the United States (GAAP). Operating earnings are not calculated in
accordance with GAAP because they exclude the impact of “special items”. Adjusted EBITDA also excludes the impact of special items
and represents Operating earnings before interest expense, investment income, taxes, depreciation and amortization. Basic EPS for
each segment is calculated by dividing segment net income (loss) on a GAAP basis by the basic weighted average shares outstanding
for the period. Basic EPS-Operating for each segment is calculated by dividing segment Operating earnings, which exclude special
items as discussed above, by the basic weighted average shares outstanding for the period. Management uses non-GAAP financial
measures such as Operating earnings, Adjusted EBITDA, FFO and Free Cash Flow to evaluate the company’s performance and
manage its operations and frequently references these non-GAAP financial measures in its decision-making, using them to facilitate
historical and ongoing performance comparisons. Additionally, management uses Basic EPS and Basic EPS-Operating by segment to
further evaluate FirstEnergy’s performance by segment and references these non-GAAP financial measures in its decision-making.
Management believes that the non-GAAP financial measures of “Operating earnings,” “Adjusted EBITDA,” “Free Cash Flow,” “Basic
EPS” and “Basic EPS-Operating” provide consistent and comparable measures of performance of its businesses to help shareholders
understand performance trends. Management uses Adjusted Equity, Adjusted Debt and Adjusted Capitalization to calculate and monitor
its compliance with the debt to total capitalization financial covenant under the FirstEnergy credit facility and term loan. These financial
measures, as calculated in accordance with the FirstEnergy credit facility and term loan, help shareholders understand FirstEnergy’s
compliance with, and incremental debt capacity under, the debt to total capitalization financial covenant. The financial covenant requires
FirstEnergy to maintain a consolidated debt to total capitalization ratio of no more than 65%, measured at the end of each fiscal quarter.
All of these non-GAAP financial measures are intended to complement, and are not considered as alternatives to, the most directly
comparable GAAP financial measures. Also, the non-GAAP financial measures may not be comparable to similarly titled measures
used by other entities.
Pursuant to the requirements of Regulation G, FirstEnergy has provided quantitative reconciliations within the presentation of the nonGAAP financial measures to the most directly comparable GAAP financial measures.
FirstEnergy FactBook
Published May 1, 2015
3
Acronyms
ABO
ACI
AD
AFUDC
ALJ
BGS
BPS
BPU
BRA
CEMS
CES
CIS
COS
DOE
DR
DSM
DSP
EDC
EE
EHV
EMAAC
ENEC
EPA
ESP
FERC
FRR
GA
GWH
HV
IGCC
ILB
ITC
kV
kWh
LCI
LNB
Lo-S
MAAC
MATS
MCI
MISO
Accumulated Benefit Obligation
Activated Carbon Injection
American Electric Power Dayton
Allowance for Funds Used During Construction
Administrative Law Judge
Basic Generation Service
Basis Points
Board of Public Utilities
Base Residual Auction
Continuous Emissions Monitoring System
Competitive Energy Services
Customer Information System
Combustion Optimization System
Department of Energy
Demand Response
Demand Side Management
Default Service Plan
Electric Distribution Company
Energy Efficiency
Extra High Voltage
EMAAC Locational Deliverability Area in PJM
Expanded Net Energy Costs
United States Environmental Protection Agency
Electric Security Plan
Federal Energy Regulatory Commission
Fixed Resource Requirement
Governmental Aggregation
Gigawatt-hour
High Voltage
Integrated Gasification Combined Cycle
Illinois Basin
Investment Tax Credit
Kilovolt
Kilowatt-hour
Large Commercial / Industrial Customers
Low NOx Burners
Low Sulfur Coal
MAAC Locational Deliverability Area in PJM
Mercury and Air Toxics Standards
Medium Commercial / Industrial Customers
Midcontinent Independent System Operator
MM
MMBTU
MW
MWH
NAPP
NDC
NDT
NOX
NRC
OCI
OFA
OPEB
OVEC
PAPUC
PBO
PIPP
PJM
POLR
PPA
Precip
PSC
PUCO
PV
RD
RMR
ROE
RPM
RPS
RTEP
RTO
SCR
SIP
SMIP
SNCR
SO2
SSO
SVC
VAR
VVC
WFGD
WV PSC
FirstEnergy FactBook
Mass Market
Million British Thermal Unit
Megawatt
Megawatt-hour
Northern Appalachian Coal
Net Demonstrated Capacity
Nuclear Decommissioning Trust
Nitrogen Oxide
Nuclear Regulatory Commission
Other Comprehensive Income
Separated Overfire Air
Other Post-Employment Benefits
Ohio Valley Electric Corporation
Pennsylvania Public Utility Commission
Projected Benefit Obligation
Percentage of Income Payment Plan
PJM Interconnection, L.L.C.
Provider of Last Resort
Purchase Power Agreement
Electrostatic Precipitator
Maryland Public Service Commission
Public Utilities Commission of Ohio
Photovoltaic
Recommended Decision
Reliability Must Run
Return on Equity
Reliability Pricing Model
Renewables Portfolio Standard
Regional Transmission Expansion Plan
Regional Transmission Organization
Selective Catalytic Reduction
Stock Investment Plan
Smart Meter Technology Procurement and Installation Plan
Selective Non-Catalytic Reduction
Sulfur Dioxide
Standard Service Offer
Static VAR Compensator
Volt-Ampere Reactive
Voltage/VAR Control
Wet Flue Gas Desulfurization
West Virginia Public Service Commission
Published May 1, 2015
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2
FirstEnergy FactBook
Published May 1, 2015
Strength in Our Diversity and Scale
Utilities
■ Approximately 6M customers
■ One of the largest contiguous
service territories in the U.S.
covering 65,000 square miles
MI
PA
Transmission
■ One of the largest
transmission systems in PJM
IL
IN
OH
MD
■ 24,000+ transmission miles
■ Significant opportunity for
growth
NJ
VA
WV
Jointly Owned Plant
Competitive Operations
■ One of the cleanest
generation fleets in the U.S.
Regulated Plants
■ Long generation vs. sales
strategy
230, 345 and 500 kV Transmission
Lines
■ Focused on reducing overall
business risk
Competitive retail footprint
Competitive Generating Plants
Utility footprint
FirstEnergy FactBook
Published May 1, 2015
5
2014 Accomplishments
Significant Regulatory Activity
Distribution
Utilities
■
■
■
■
Rate Case filing in WV
Rate Case filings in PA
Filed ESP IV in Ohio; Stipulation filed on December 22, 2014
2011 and 2012 storm costs in NJ approved; favorable CTA decision
Launched “Energizing the Future” Growth Plan
Transmission
Business
■ Initial year spend of $1.4B
■ Significant opportunities going forward
■ On December 31, 2014, FERC accepted ATSI forward-looking formula rate and
initiated review of ROE; both actions are subject to potential review
Changed the Character and Operation of the Fleet
Competitive
Operations
■
■
■
■
■
Minimized downside risk and positioned for potential upside
Sold 527MW of hydro assets
Adjusted sales strategy; sell no more than we produce
Advocated market reforms
Conservation of capital – Modest MATS spend, deferred BV2 steam generator and reactor head replacement
Focus on Financial Success
Financial
■ Revised dividend to $1.44 per share; fully supported by regulated businesses
■ Extended $6B in credit facilities through March 2019
■ Completed inaugural bond issuance at FET; ATSI bond offering to support growth
program
■ $83M of equity through stock investment/employee benefit plans
As of December 31, 2014
FirstEnergy FactBook
Published May 1, 2015
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FirstEnergy FactBook
Published May 1, 2015
Going Forward … Growth Through Investments in Regulated
Operations
Grow
Regulated
Operations …
… Repositioned
Competitive
Operations
Competitive Operations
Regulated Operations
■ Reduced size of fleet and changed mix of
assets to a much stronger platform of units
■ Retain upside potential as markets improve,
but limit downside from continued depressed
conditions
■ Targeting positive cash flow each year,
2015-2018
■ Increase transmission investments
■ Target average annual transmission earnings
growth of 20%+ at ATSI and TrAILCo through 2017
■ Grow predictable cash flow
■ Seek opportunities in select rate case filings
■ Continue to support a strong dividend
Regulated Business targeting 80%+ of EPS
FirstEnergy FactBook
Published May 1, 2015
7
FirstEnergy Leadership
Charles E. Jones
President and Chief
Executive Officer
Lynn M. Cavalier
Senior Vice President,
Human Resources
James F. Pearson
Senior Vice President
and Chief Financial
Officer
James H. Lash
President
FirstEnergy Generation
Samuel L. Belcher
President and Chief
Nuclear Officer
FirstEnergy Nuclear
Operating Company
John W. Judge
Vice President,
Corporate Risk and
Chief Risk Officer
Donald R. Schneider
President
FirstEnergy Solutions
Michael J. Dowling
Senior Vice President,
External Affairs
Irene M. Prezelj
Vice President,
Investor Relations
FirstEnergy FactBook
Steven R. Staub
Vice President,
Treasurer
Leila L. Vespoli
Executive Vice
President, Markets and
Chief Legal Officer
Steve Strah
Senior Vice
President and
President of
FirstEnergy Utilities
Bennett L. Gaines
Senior Vice President,
Corporate Services and
Chief Information Officer
K. Jon Taylor
Vice President,
Controller and Chief
Accounting Officer
Published May 1, 2015
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4
FirstEnergy FactBook
Published May 1, 2015
Summary Organizational Structure
FirstEnergy Corp.*
(FE)
Monongahela Power
Company*
(MP)
Jersey Central Power
& Light Company*
(JCP&L)
The Potomac Edison
Company*
(PE)
Metropolitan Edison
Company
(ME)
West Penn Power
Company*
(WPP)
Pennsylvania Electric
Company
(PN)
The Waverly Electric
Light and Power
Company
Ohio Edison
Company*
(OE)
Pennsylvania Power
Company
(PP)
The Cleveland
Electric Illuminating
Company*
(CEI)
The Toledo
Edison Company*
(TE)
FirstEnergy
Transmission, LLC
(FET)
American
Transmission
Systems,
Incorporated
(ATSI)
Trans-Allegheny
Interstate Line
Company
(TrAILCo)
FirstEnergy Solutions
Corp.*
(FES)
FirstEnergy Nuclear
Generation, LLC
(FENUGENCO)
FirstEnergy
Generation, LLC*
(FEGENCO)
FirstEnergy Nuclear
Operating Company
(FENOC)
Allegheny Energy
Supply Company,
LLC*
(AE Supply)
Allegheny
Generating Company
(AGC)
AET PATH Company,
LLC *
(PATH)
FE Utilities
FE Transmission
Competitive Energy Services
*Entity has subsidiaries that are not shown
FirstEnergy FactBook
9
Published May 1, 2015
FirstEnergy Corp. Segment Descriptions
Regulated
Distribution
Comprised of ten distribution companies serving ~6M customers in Ohio,
Pennsylvania, New Jersey, West Virginia, Maryland and New York, making this one
of the largest contiguous service territories in the U.S. Our regulated generation
portfolio consists of 3,790 MW and serves primarily West Virginia. Net plant inservice as of 12/31/2014 was approximately $17.2B.
Regulated
Transmission
The FirstEnergy transmission system spans a 65,000 square mile service territory
and is one of the largest transmission systems in PJM with over 24,000
transmission miles. The lines are owned by certain distribution companies or FE’s
transmission companies, ATSI and TrAILCo. ATSI consists of the transmission
systems formerly owned by OE, PP, CEI, and TE along with additions constructed
by ATSI. TrAILCo consists of TrAIL, a 500-kV transmission line, and other
transmission facilities constructed in the service areas of WPP, MP, PE, ME and
PN. Net plant in-service as of 12/31/2014 was approximately $5B.
Competitive Energy
Services (CES)
FES and AE Supply primarily comprise the Competitive Energy Services segment,
which serves customers in the POLR, Governmental Aggregation, and selected
large commercial-industrial direct sales channels. FirstEnergy’s competitive
generating portfolio consists of more than 13,000 MW of diversified capacity. The
segment is long generation versus sales.
Corporate / Other
Corporate/Other contains corporate support and other businesses that are below
the quantifiable threshold for separate disclosure as a reportable segment and
interest expense on stand-alone holding company debt and corporate income
taxes. Additionally, reconciling adjustments for the elimination of inter-segment
transactions are included in Corporate/Other.
FirstEnergy FactBook
Published May 1, 2015
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5
FirstEnergy FactBook
Published May 1, 2015
Regulated Distribution
State
Ohio
Pennsylvania
New Jersey
West Virginia
Maryland
New York
Total
2014 Customers
(in thousands)
2,089
2,026
1,103
527
259
4
6,008
FirstEnergy FactBook
2014 Distribution Sales
(MWH in thousands)
54,173
52,542
20,813
15,024
7,001
–
149,553
As of December 31, 2014
Published May 1, 2015
11
Regulatory Strategy
State
Company Regulatory Activity
New Jersey
JCP&L
• Filed distribution rate case November 30, 2012
• ALJ filed initial decision on January 8, 2015
• Base Rate Case and Generic Storm Proceeding BPU orders issued March 26, 2015
• April 1, 2015: effective date of new rates
• Generic Storm Proceeding stipulation approved March 19, 2014
• Generic Consolidated Tax Adjustment Proceeding order issued October 22, 2014
West Virginia
MP
• MP/PE Rate Case filed April 30, 2014; Amended filing made on June 13, 2014
• Rate Case settlement filed with the PSC on November 3, 2014
• Settlement approved without modification by the WVPSC on February 3, 2015
• February 25, 2015: effective date of new base rates and vegetation management surcharge
• ENEC case: Filed August 29, 2014 requesting $65.8M increase based on fuel and purchased power
costs; Settlement filed December 2, 2014, with hearing on December 3, 2014; Settlement defers $16.8M
for recovery in 2016 and delays the ENEC rate change until February 25, 2015; Settlement approved
without modification by the WVPSC on January 29, 2015
PE – WV
Pennsylvania
PP
ME
PN
WPP
Ohio
OE
CEI
TE
Maryland
PE – MD
• Rate Case filings made for all four companies on August 4, 2014
• Settlements filed on February 3, 2015
• ALJ Recommended Decisions issued March 16, 2015 and March 17, 2015
• PAPUC issued Orders approving Settlements April 9, 2015
• May 3, 2015: effective date of new rates
• Default Service Plan settlement for June 2015-May 2017 approved by PAPUC
• Base distribution rate freeze through May 2016 per ESP 3
• ESP IV (Powering Ohio’s Progress) filed August 4, 2014
• Stipulation filed on December 22, 2014
• Evidentiary hearings scheduled to begin June 15, 2015
• Alternative Energy Rider refund ruling appealed to the Supreme Court of Ohio in December 2013
• No rate cases currently planned
• Continue to monitor potential for Smart Meter and Incremental Investment Riders
FirstEnergy FactBook
Published May 1, 2015
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FirstEnergy FactBook
Published May 1, 2015
Rate Base and Allowed ROEs
State
Ohio
Company
Rates Effective
Rate Base
($M)
Allowed
Debt /Equity
Allowed
ROE
OE
January 2009
$ 1,251
Debt 51.0% / Equity 49.0%
CEI
May 2009
$
984
Debt 51.0% / Equity 49.0%
10.50%
TE
January 2009
$
414
Debt 51.0% / Equity 49.0%
10.50%
PP
May 2015
~$ 360
Debt 49.9% / Equity 50.1%
ME
May 2015
~$ 1,410
Debt 50.0% / Equity 50.0%
10.50%
Pennsylvania*
New Jersey
PN
May 2015
~$ 1,540
Debt 50.1% / Equity 49.9%
WPP
May 2015
~$ 1,290
Debt 49.9% / Equity 50.1%
JCP&L
April 2015
$ 2,089
Debt 50.0% / Equity 50.0%
PE – WV
February 2015
~$ 2,500
Debt 53.5% / Equity 46.5%
MP
February 2015
~$ 2,500
PE – MD
February 1993
9.75%
West Virginia*
Maryland
$
581
Debt 53.5% / Equity 46.5%
Debt 56.0% / Equity 44.0%
11.90%
As of the most recent rate case approved by respective state commissions. Rate base can include distribution, transmission and
generation assets but actual required revenues are adjusted to reflect current rate structure.
* Reflects filed rate base and debt/equity; final settlements/Orders do not specifically include rate base or capital structure
Published May 1, 2015
FirstEnergy FactBook
13
Summary of Rate Proceeding Requirements
Ohio
General
Time Limitations Between
Cases
Fuel Clause Renewal
Frequency
Notice of Intent
Prior Notice Required
Notice Period (Days)
Pennsylvania
New Jersey
West Virginia
Maryland
No
No
No
No
No
N/A
N/A
N/A
Annually
N/A
Yes
30
Yes
30
No
N/A
Yes
30
Yes
30
Hybrid (Historic/
Forecast)
12 Month Historic
12 Month Forecast
12 Month Fully
Projected Future
Test Year
Hybrid (Historic/
Forecast)
Historic
Hybrid (Historic/
Forecast)
Yes*
Yes
Yes
No
Yes
9 months
9 months
1-9 months
N/A
1-8 months
ESP 3
through May 2016
Current DSP
through May 2015
Evergreen
N/A
Standard Offer
Service
Case Components
Base Case Test Year
Other
Requested (but not
approved) Rates Effective
Subject to Refund
Approximate number of
months after filing to
implement rates subject
to refund
Default Service
Term
(SOS)–Periodic Filing
* This provision is subject to other requirements including the filing of a bond or letter of credit
FirstEnergy FactBook
Published May 1, 2015
14
7
FirstEnergy FactBook
Published May 1, 2015
Summary of Recovery Mechanisms
Company
Purchased
Power1/ Fuel
Rider
Incremental
Capital Recovery
Storm Cost
Recovery2
Energy
Efficiency
Smart Meter /
Smart Grid7
Alternative
Energy4,8,9
OE
Annually
Base Rates
Quarterly
Semi Annually
Quarterly3
Quarterly
CEI
Annually
Base Rates
Quarterly
Semi Annually
Quarterly3
Quarterly
TE
Annually
Base Rates
Quarterly
Semi Annually
Quarterly3
Quarterly
PP
Quarterly
Base Rates
No
Annually
Annually
Annually
ME
Quarterly
Base Rates
No
Annually
Annually
Annually
PN
Quarterly
Base Rates
No
Annually
Annually
Annually
WPP
Quarterly
Base Rates
No
Annually
Annually
No-Supplier
Obligation5
JCP&L
Annually
Annually
No
Annually
Annually
Base Rates/SRC
Rider
Base Rates
No
PE – WV
No
Annually
No
N/A
MP
Annually
Base Rates
No
Annually
No
N/A
PE – MD
Various6
Base Rates
No
Annually
No
No-Supplier
Obligation
Notes:
1. Purchased Power is associated with competitive solicitations in all states except West Virginia. Ohio changes annually, reconciled quarterly.
2. Storm Costs that exceed baseline amounts are authorized to be deferred in New Jersey and Ohio. All non-extraordinary storm costs in Pennsylvania are
authorized to run through a storm reserve account; companies may seek deferral of expenses related to extraordinary storms. Storm-related vegetation
management costs are recovered through a surcharge mechanism in WV. In Maryland, the company may seek deferral of costs.
3. Smart Meter in Ohio is currently a pilot program with a limited number of meters and equipment; 50% of funding from DOE.
4. Pennsylvania only recovers Solar Renewable Energy Credits. The non-solar obligation remains with the supplier. In Ohio, both solar and non-solar renewable
energy credits are recovered.
5. Less existing long-term Tier I Alternative Energy Credits that are recoverable through the Price To Compare.
6. Residential is updated twice a year. Commercial and Small Industrial change quarterly. Large industrial customers have Hourly Pricing Service.
7. Costs in New Jersey and Ohio for the Smart Grid Initiative are recovered through riders; 50% of funding from DOE.
8. New Jersey RPS requirements are the responsibility of the BGS suppliers.
9. West Virginia repealed its Alternative and Renewables Portfolio Act in February 2015.
FirstEnergy FactBook
Published May 1, 2015
15
Published May 1, 2015
16
Net Regulatory Asset Amortization (Deferral)
($ Millions)
Jurisdiction
2014A
2015F
Ohio
$71
$140
Pennsylvania
($14)
$80
New Jersey
$32
$100
West Virginia / Maryland
($89)
($15)
FERC
$12
$12
Total
$12
$317
FirstEnergy FactBook
8
FirstEnergy FactBook
Published May 1, 2015
Renewable Energy Requirements
NJ
MD
Year
2026**
2021
2021
2022
Requirements
12.5%
OH
18.5%
23.85%
20%
Class/Tier I – Non Solar
12.0%
8.0%
17.88%
Solar
0.5%
0.5%
3.47%
2%
–
10.0%
2.5%
2.5% until 2018
Class/Tier II
Default Service RPS
Obligations Fulfilled By
Procurement Method /
Market Incentive (NJ)
Solar
Class/Tier I/ Renewable
Energy Resources
Other Provisions
18%
■ 100% Company
■ Company 100% solar for ME,
PN & PP / Suppliers Tier I,
Tier II & WPP solar
■ Suppliers
■ RFP & limited spot
■ RFP
■ Financing Program /
■ Spot
Auction sales to Suppliers
■ Solar PV and Solar
Thermal
■ Solar PV and Solar Thermal
■ Solar PV and Solar
Thermal
■ Solar PV, Solar Thermal &
Solar Water Heating
■
■
■
■
■
■
■
■
■
Solar
Wind
Hydro
Geothermal
Solid waste *
Biomass
Fuel cells
Storage *
Distributed
generation*
■ Certain advanced
energy resources*
■
■
■
■
■
■
■
■
■
■
Solar Photovoltaic
Solar Thermal
Wind
Low-impact hydro
Geothermal
Biomass
Methane gas*
Coal-mine methane
Fuel cells
Wood
byproducts*
■ Large-scale hydro*
■ Solar
■ Wind
■ Fuel Cells powered by
Renewable fuels
■ Wave / Tidal
■ Geothermal technologies
■ Methane Landfill gas
■ Anaerobic Digestion
■ Biomass (sustainable)
■ In State hydro <3 with in
service date >7/23/12
■
■
■
■
■
■
■
■
■
■
■
■ N/A
■
■
■
■
■
■
■
■
■ Small hydro <30
■ Resource recovery
■ Hydro (excluding pumped
storage)
5 years
3 years
Solar 5 Years, Class I 3
years & Class II 1 year
3 years
Panel to review the
RPS legislation
Quarterly Adjustments to Tier I
Non-Solar %
Solar must be in-state
Solar must be in-state
Class/Tier II
Advanced/Alternative
Energy Resources
Renewable Energy
Credit (REC) Life
PA
Waste coal
Distributed generation
DSM
Large hydro
Muni solid waste
Wood byproducts *
IGCC coal
Pumped-storage hydro
■ Suppliers 100% residential
& commercial / Company
100% industrial
Solar
Wind including Off-Shore*
Biomass
Landfill Gas
Small Hydro
Geothermal Electric
Fuel Cells*
Municipal Solid Waste
Ocean
Poultry litter incineration*
Refuse derived
*Additional restrictions and provisions apply
**Changes under SB310 extended RPS requirements from 2024 to 2026 due to freezing requirements barring outcome of panel review of legislation
Published May 1, 2015
FirstEnergy FactBook
17
Regulated Distribution Sales Trends
Percent of 2007 Deliveries
105
RES +0.1%
TOTAL -1.4%
IND
-0.9%
COM -3.9%
100
95
90
85
80
2007
2008
2009
2010
2011
2012
2013
2014
*
2015 F*
Distribution sales have not fully recovered from 2007 levels,
but have shown improvement since 2012
*Assumes normal weather
FirstEnergy FactBook
Published May 1, 2015
18
9
FirstEnergy FactBook
Published May 1, 2015
Strengthening Our Utilities
Projected Load Growth
Load Growth by Class
Load Growth – Industrial Sector
2012 - 2015
2014A - 2019F
M MWH
GWH
55
10,000
50
8,000
45
6,000
40
4,000
35
2,000
Potential Shale Load
Growth from Existing
Shale Load in 2013
Industrial Growth
-
30
Residential
2012A
Commercial
2013A
2014A
Industrial
2013
2014
2015
2016
2017
2018
2019
2015F
■ 2015F ~151M MWH vs. 2014A of 149.5M MWH
■ 2013-2019 Industrial growth ~14%
■ Majority of load growth driven by Industrial sector
■ Shale accounts for ~50% of Industrial growth
Overall 2015 load growth of 0.9%
Significant 5-year growth projected in shale sector
FirstEnergy FactBook
Published May 1, 2015
19
Leveraging Industrial and Technological Developments in our Region
■ FE utility service territory overlays Marcellus and Utica shale region
■ Although shale is in early stages of development, there are signs of
load growth
– ~400 MW (Operational 2013 – 2014)
– ~2.5M – 3.0M MWH of annual load growth
– ~1,000 MW (2015 – 2019)
– ~5.8 – 6.8M MWH of additional load growth
■ Shale development also creating other opportunities
– Steel and tubing companies benefit from large upstream infrastructure build
– Midstream companies of substantial size being connected
– Cracker plants that convert ethane and natural gas are being considered
– Related supply chains being established
FirstEnergy FactBook
Published May 1, 2015
20
10
FirstEnergy FactBook
Published May 1, 2015
Growing Our Transmission Business
Energizing the Future
■ Regulatory Required: PJM mandated RTEP projects including those that support
generation deactivations and shale gas expansion activities
■ Reliability Enhancement: Projects focused on enhancing customer service,
strengthening grid and cyber-security, and adding resiliency and operating flexibility
Utilities
Stand Alone Businesses
Potter
Toledo
Cabot
PA
PA
Cleveland
345 & 500 kV
Wylie Ridge
Kammer
Akron
Youngstown
230 kV
502 Junction
Pleasureville
Black Oak
Beddington
115 & 138 kV
NJ
MD
Doubs
NJ
N. Shenandoah
MD
Mt. Storm
Meadow
Brook
Illuminating Company
Ohio Edison
Penn Power
Toledo Edison
Springfield
Loudoun
VA
Pennsylvania
Met-Ed
Penelec
West Penn Power
WV
Transmission Line
Operating Voltage
138 kV
69 kV
Substation
FirstEnergy Utility Service Area
FirstEnergy VA Transmission Zone
TrAIL 500 kV Line
Substation
FE TrAIL 50% Joint Ownership with
Dominion Resources
Dominion Resources Owned
■ Established in 1998
■ Forward-looking Formula Rate –
12.38% ROE*
■ ~7,400 transmission miles
■ 2014 revenues ~$242M
■ PP&E*** – $1.8B
■
■
■
■
■
WV
West Virginia/Maryland
Mon Power
Potomac Edison
■
■
■
■
Established in 2006 – In Service May 2011
Forward-looking Formula Rate 11.7% ROE
~300 transmission miles
2014 revenues ~$214M
PP&E*** – $1.5B
New Jersey
Jersey Central
Power & Light
Utility Stated Rates
16,300+ transmission miles**
2014 revenues ~$300M
PP&E*** – $1.7B
$4.2B Investment – 2014-2017
*On December 31, 2014, FERC accepted, subject to potential refund, ATSI’s rate filing to amend its formula rate to a forward-looking test year effective January 1,
2015. FERC also determined the ROE is subject to inquiry and potential refund as part of the settlement and hearing proceedings.
** Includes lines 23kV and above
*** Property, Plant & Equipment (PP&E) in-service net of accumulated depreciation as of December 31, 2014
FirstEnergy FactBook
Published May 1, 2015
21
FirstEnergy Transmission – Overview
PA
OH
NJ
MD
VA
345 & 500 kV
WV
230 kV
24,000+ transmission miles*
115 & 138 kV
 ~7,700 ATSI, TrAILCo
 16,300+ utilities
*Includes lines 23kV and above
Note: Map does not represent 69kV lines and below
FirstEnergy FactBook
Published May 1, 2015
22
11
FirstEnergy FactBook
Published May 1, 2015
FirstEnergy Generation Portfolio
Renewables 1,906 MW
Nuclear
Beaver Valley 1& 2
Perry
Davis-Besse
MW
1,872
1,268
908
Total
4,048
Supercritical Coal
Mansfield 1-3
Harrison 1-3 (R)
Pleasants 1-2
Sammis 6 & 7
Fort Martin 1 & 2 (R)
2,490
1,984
1,300
1,200
1,098
Total Supercritical Coal
8,072
Solar 20 MW
Wind 476 MW
Hydro 1,410 MW
Gas/Oil
1,599
MW
Total Gas/Oil
Nuclear
4,048
MW
1,410
Wind
Subcritical Coal
1,146
OVEC (PR)
188
Regulated: 11 Competitive: 177
Total Capacity
16,959 MW
Total Subcritical Coal
Competitive
13,169 MW
(78%)
3,790 MW
(22%)
Regulated
1,599
Total Hydro
Subcritical Coal
Sammis 1-5
1,010
Bay Shore 1
136
1,334
MW
638
545
88
88
86
45
43
66
Hydro
Bath County (PR)
1,200
Regulated: 487 Competitive: 713
Yards Creek (R)
210
Coal
9,218
MW
OVEC
188 MW
Gas/Oil
Springdale 1-5
West Lorain 1-6
Chambersburg 12 & 13
Gans 8 & 9
Forked River
Hunlock
Buchanan
Other
Blue Creek
High Trail
Allegheny Ridge
N. Allegheny Ridge
Highland
Casselman
Meyersdale
100
99
80
70
62
35
30
Total Wind
476
Solar
(R) Fully Regulated or (PR) Partially Regulated units
Maryland Solar
20
Long-term PPA
Total Solar
20
FirstEnergy FactBook
Published May 1, 2015
23
12
FirstEnergy FactBook
Published May 1, 2015
Creating Value for Investors
Ohio Operations
FirstEnergy FactBook
24
Published May 1, 2015
Ohio – Customer Data
2014 Total Customers (thousands)
Ohio Edison
Major
Metropolitan Areas
1,036
The Illuminating Company (CEI)
Toledo Edison
Total
745
Cuyahoga County
(Cleveland)
308
Summit County
(Akron)
542
Lucas County
(Toledo)
442
Mahoning/Trumbull
Counties
(Youngstown)
449
Total State of Ohio
11,540
2,089
Typical Bill Comparison*
Ohio
Population
(thousands)
$/Month
Ohio Edison
$133.90
The Illuminating Company
(CEI)
$131.66
Toledo Edison
$132.39
Statewide Avg. Bill
$139.33
1,278
Source: U.S. Census Bureau (2010)
Principal Industries Served**
Primary Fabricated Metals
Automotive
Chemical
* Typical bills are displayed on 1,000 kWh of residential
usage. Billing amounts sourced from the EEI Typical
Bills and Average Rates Report as of July 1, 2014.
Ohio rates represent POLR bundled residential rates.
Plastic and Rubber
Petroleum
** Based on kWh sales
As of December 31, 2014
FirstEnergy FactBook
Published May 1, 2015
25
13
FirstEnergy FactBook
Published May 1, 2015
Ohio – Distribution Sales
M MWH
54.2
54.5
21.1
21.8
15.6
15.6
60
50
State Unemployment Rates
OH
40
2007
2011
2012
2013
2014
30
5.6%
8.7%
7.4%
7.3%
5.8%
20
Source: Moody’s Analytics
10
17.5
17.1
2014A
2015F
0
M MWH
Residential
60
50
54.2
54.5
10.6
10.7
18.7
18.8
Commercial*
Industrial
*Includes Street Lighting
Gross Domestic Product Annualized Growth
(Seasonally Adjusted Annualized Rate)
40
30
OH
2007
2011
2012
2013
2014
-0.8%
2.6%
3.1%
1.8%
0.3%
20
Source: Moody’s Analytics
10
24.9
25.0
2014A
2015F
Gross Domestic Product, in 2009 dollars
0
OE
CEI
($ billions)
TE
Note: Forecasted sales assume normal weather.
Includes forecast for state energy efficiency mandates.
(State mandate 4.2%. Approximately 2.3M MWH)
OH
2007
2011
2012
2013
2014
$509
$501
$517
$526
$528
Source: Moody’s Analytics
FirstEnergy FactBook
Published May 1, 2015
26
Published May 1, 2015
27
Ohio – Political Landscape
Governor
Governor
John Kasich (R)
Current Term
Expires in 2019
Public Utilities Commission of Ohio (PUCO)
Commissioners
Current Term
Andre T. Porter, Chairman (R)
Expires in 2020
Asim Z. Haque, Vice Chairman (I)
Expires in 2016
Lynn Slaby (R)
Expires in 2017
M. Beth Trombold (I)
Expires in 2018
Thomas W. Johnson (R)
Expires in 2019
FirstEnergy FactBook
14
FirstEnergy FactBook
Published May 1, 2015
Ohio – Regulatory Update
Ohio ESP 3
■ Approved by the PUCO on July 18, 2012
■ Plan covers June 1, 2014, thru May 31, 2016
■ Stabilizes pricing by modifying the previous POLR competitive bidding
schedule
■ Freezes base distribution rates through May 31, 2016
■ Continues Delivery Capital Recovery rider to earn a return on and of
incremental distribution plant in service since last rate case
– Up to $405M in revenue for period covered by ESP 3
■ Continues collection of lost distribution revenues associated with energy
efficiency and peak demand reduction programs
■ Extends recovery period for REC costs (with carrying charges) –
reducing current monthly charges for non-shopping customers by more
than 50%
■ Provides PIPP customers with 6% discount off their price-to-compare
with wholesale generation supply provided by FE Solutions
Published May 1, 2015
FirstEnergy FactBook
28
Ohio – Regulatory Update
Ohio ESP 3 – Delivery Capital Recovery Rider
Recovery Period
Revenue Cap
Jan 2012 – Dec 2012
$150
Jan 2013 – Dec 2013
$165
($ Millions)
Jan 2014 – May 2014
$75
Jun 2014 – May 2015
$195
Jun 2015 – May 2016
$210
■ Individual company revenue caps are determined by the following
percentages applied to the total revenue cap
– CEI: up to 70%
– OE: up to 50%
– TE: up to 30%
■ Any recovery period shortfall or overage will be applied to the
subsequent period
FirstEnergy FactBook
Published May 1, 2015
29
15
FirstEnergy FactBook
Published May 1, 2015
Ohio – Regulatory Update
Ohio ESP IV – Powering Ohio’s Progress*
Continues to build upon the success of current
and prior ESPs
■ Filed: August 4, 2014
■ Term: June 1, 2016 – May 31, 2019
■ As proposed:
– Continues successful competitive bid process for POLR load
– Freezes base distribution rates through May 31, 2019
– Continues Delivery Capital Recovery rider with revenue increase caps proposed at $30M
per year
– Continues collection of lost distribution revenue associated with energy efficiency and peak
demand reduction programs
– Includes Economic Stability Program
■ Stipulation with 15 signatory parties filed on December 22, 2014
– Accepts the terms of the Ohio Companies’ Application except as modified by the
Stipulation which includes provisions related to rate design, economic development,
energy efficiency, and support for low income customers
* Subject to regulatory approval
Published May 1, 2015
FirstEnergy FactBook
30
Ohio – Regulatory Update
1 Plants Serving Ohio Customers
Davis-Besse
WH Sammis
OVEC
908 MW
2,220 MW
116 MW
740 Employees
396 Employees
467 OH Employees
Economic Stability Program*
Capacity, Energy and
Ancillary Services
Cost-Based
Payments
Sell Capacity, Energy and
Ancillary Services into the
Wholesale Market
3
1 ■ FE’s Ohio utilities enter into a
15-year purchased power contract
with FES
■ Purchase power from Davis-Besse,
Sammis and a portion of OVEC
■ Utilities pay FES a cost-based rate
for power
2 ■ Utilities sell power into
wholesale market
3
■ When wholesale market revenues
exceed cost, customers receive
credit
■ When wholesale market revenues
are less than cost, customers
pay charge
■ Cost-based arrangement protects
all customers from retail price
volatility
2
Wholesale
Market Revenues
■ Customers projected to save $2B over
15 years
Note:
■ Non-shopping customers continue to
receive generation from competitive
auction process
■ All customers retain option to shop for a
competitive retail electric supplier
* Subject to regulatory approval
FirstEnergy FactBook
Published May 1, 2015
31
16
FirstEnergy FactBook
Published May 1, 2015
Ohio – Regulatory Update
■ Amended Energy Efficiency Filing
– Ohio Senate Bill 310 provides the opportunity to lower customers’ costs while continuing to
meet the state’s energy efficiency requirements for 2015 and 2016
– On November 20, 2014 the Ohio Companies received approval of their Amended Energy
Efficiency Plan to reduce customers’ costs while aligning with the state’s recent action to
freeze energy efficiency mandates for 2015-2016
– Certain large industrial customers have the ability to opt out of utility-sponsored programs
and implement their own energy efficiency initiatives
■ Alternative Energy Rider Case
– PUCO issued an Opinion and Order on August 7, 2013, disallowing $43.4M plus carrying
costs in Renewable Energy Credit purchases
– The Ohio Companies and Intervenors filed Applications for Rehearing on
September 6, 2013
– The PUCO granted the Applications for Rehearing for further consideration on September
18, 2013
– A Second Entry on Rehearing from the PUCO was issued on December 18, 2013, denying
the Application for Rehearing filed by the Ohio Companies and Intervenors
– The Ohio Companies filed an appeal and motion to stay with the Supreme Court of Ohio
on December 24, 2013. The stay was granted on February 10, 2014, and went into effect
February 14, 2014.
32
Published May 1, 2015
FirstEnergy FactBook
Ohio – Energy Efficiency
Mandates and Progress
Ohio
State Goals
Smart Grid
Senate Bill 310*
Cross-cutting**
Technologies/Programs
4.20% in 2015 (2,266 GWH)*
Energy Efficiency 4.20% in 2016 (2,288 GWH)*
5.20% in 2017 (2,832 GWH)*
Demand
Response
Smart Meter
4.75% in 2015 (552 MW)*
4.75% in 2016 (545 MW)*
5.50% in 2017 (630 MW)*
Status
PUCO approved Phase II pilot DR expansion
for total up to 44,000 meters. Opt-in DR
Pricing program available to most pilot
customers in 2014.
Cost Recovery for
In place; semi-annual energy efficiency rider
Energy Efficiency
Compliance
Distribution Automation
$27
Volt / VAR Control
$10
Consumer Behavior Study
$30
No state smart meter requirement
*Senate Bill 310 freezes 2015 and 2016 energy efficiency and demand response requirements at
4.20% EE, 4.75% DR, with escalating requirements 2017-2027 subject to the outcome of the
legislative study committee. The GWh and MW goal estimates shown above do not incorporate
potential reductions from qualifying C&I customers that may elect to opt-out of the Companies’
Energy Efficiency programs and target baseline.
Smart Meter
CEI
($67M)
2014 EE & DR targets met based on
preliminary data
On track to achieve 2015 EE & DR targets
FirstEnergy FactBook
■ Period of performance = 60 months
(June 2, 2010 – June 1, 2015)
■ Implementation of all programs
during 2014
■ All just and reasonable costs are
fully reimbursable via federal grant
and state approved riders (subject
to audit)
**Cross-cutting describes a project that includes communications
and control systems that support more than one component of
the smart grid
Published May 1, 2015
33
17
FirstEnergy FactBook
Published May 1, 2015
Ohio – Smart Grid Modernization Initiative Update
■ Project Status: 99% Complete
■ Remaining Work
– Consumer Behavior Study (CBS) Final Report
– Metrics & Benefits Reporting
■ $63M of $67M spent through 1Q 2015
Department of Energy
Agreement Terminates
Complete CBS Phase 2
Additional 30,000 Meters & In-Home
Technologies Installation (OH)
PUCO Approved
CBS Phase 2 (OH)
Pilot Rates CBS Phase 2 &
Continue Phase 1 (OH)
Completed Year 2
Pilot Rates CBS
Phase 1 (OH)
2Q
2013
3Q
2013
4Q
2013
Distribution
Automation (DA) &
Volt/Var Control
(VVC) Operational
6/1/13
1Q
2014
2Q
2014
3Q
2014
4Q
2014
2015
Metrics and Benefits Data
Collection Completed
DA & VVC
Automatic
Published May 1, 2015
FirstEnergy FactBook
34
Ohio – Procurement Schedule
Ohio Edison, The Illuminating Company (CEI) and Toledo Edison
ESP 3
Delivery Period
Auction
Tranches Bid*
Oct-12
17
Jan-13
17
June 2013 –
May 2014
16
24 Months
$59.99 / MWH
12 Months
$55.83 / MWH
24 Months
$68.31 / MWH
17
16
Jan-14
17
16
Jan-15
16
June 2015 –
May 2016
36 Months
$60.90 / MWH
36 Months
$59.17 / MWH
12 Months
$50.91 / MWH
Oct-13
Oct-14
June 2014 –
May 2015
12 Months
$73.82 / MWH
12 Months
$69.18 / MWH
*Each tranche represents 1% of the actual hourly energy and daily capacity required to serve SSO load; tranches are full-requirements products
FirstEnergy FactBook
Published May 1, 2015
35
18
FirstEnergy FactBook
Published May 1, 2015
Ohio – Long-Term Debt Schedules
Company
Ohio Edison
Type
CUSIP
Interest
Rate
Maturity
Amount
Outstanding
First Mortgage Bond
677347CG9
8.25%
10/15/2018
$25,000,000
Senior Note
677347CE4
6.875%
7/15/2036
$350,000,000
First Mortgage Bond
677347CF1
8.25%
10/15/2038
$275,000,000
OE Total
Ohio Edison
Funding LLC
Phase-In Recovery Bond 33766QAA5
0.679%
1/15/2017*
$5,977,864
Phase-In Recovery Bond 33766QAB3
1.726%
1/15/2020*
$10,202,000
Phase-In Recovery Bond 33766QAC1
3.450%
1/15/2034*
$123,612,000
OE Funding LLC Total
Senior Note
The
Illuminating
Company
(CEI)
$650,000,000
186108CF1
5.7%
4/1/2017
$139,791,864
$130,000,000
Secured Note
186108BU9
7.88%
11/1/2017
$300,000,000
First Mortgage Bond
186108CH7
8.875%
11/15/2018
$300,000,000
$300,000,000
First Mortgage Bond
186108CJ3
5.5%
8/15/2024
Senior Note
186108CE4
5.95%
12/15/2036
$300,000,000
CEI Total
* Expected Final Maturity Date
$1,330,000,000
As of March 31, 2015
Published May 1, 2015
FirstEnergy FactBook
36
Ohio – Long-Term Debt Schedules
Type
CUSIP
Interest
Rate
Maturity
Amount
Outstanding
Phase-In Recovery Bond
33766QAA5
0.679%
1/15/2017*
$32,703,861
Phase-In Recovery Bond
33766QAB3
1.726%
1/15/2020*
$56,383,000
Phase-In Recovery Bond
33766QAC1
3.450%
1/15/2034*
$103,160,000
Senior Secured Notes
889175BE4
7.25%
5/1/2020
$50,000,000
Senior Secured Notes
889175BD6
6.15%
5/15/2037
$300,000,000
Company
CEI Funding
LLC
CEI Funding LLC Total
Toledo
Edison
TE Total
Toledo
Edison
Funding LLC
$192,246,861
$350,000,000
Phase-In Recovery Bond
33766QAA5
0.679%
1/15/2017*
$2,171,530
Phase-In Recovery Bond
33766QAB3
1.726%
1/15/2020*
$3,883,000
Phase-In Recovery Bond
33766QAC1
3.450%
1/15/2034*
TE Funding LLC Total
$35,711,000
$41,765,530
* Expected Final Maturity Date
As of March 31, 2015
FirstEnergy FactBook
Published May 1, 2015
37
19
FirstEnergy FactBook
Published May 1, 2015
Creating Value for Investors
Pennsylvania Operations
Published May 1, 2015
FirstEnergy FactBook
38
Pennsylvania – Customer Data
2014 Total Customers (thousands)
Penelec (Includes NY – 4)
588
Met-Ed
558
Penn Power
163
West Penn Power
721
Total
2,030
Major Metropolitan Areas
Typical Bill Comparison*
Pennsylvania
$/Month
Penelec
$142.70
Met-Ed
$140.40
Penn Power
$122.55
West Penn Power
$105.00
Statewide Avg. Bill
$142.64
* Typical bills are based on 1,000 kWh of residential usage.
Billing amounts sourced from the EEI Typical Bills and
Average Rates Report as of July 1, 2014. Pennsylvania rates
represent Default Service Provider bundled residential rates.
York County (York)
Berks County (Reading)
Westmoreland County (Greensburg)
Erie County (Erie)
Total State of Pennsylvania
Population
(thousands)
436
412
365
281
12,711
Source: U.S. Census Bureau (2010)
Principal Industries Served**
Primary and Fabricated Metals
Coal Mining
Chemical
Plastic and Rubber
Non-Metallic Minerals
** Based on kWh sales
FirstEnergy FactBook
As of December 31, 2014
Published May 1, 2015
39
20
FirstEnergy FactBook
Published May 1, 2015
Pennsylvania – Distribution Sales
M MWH
60
52.5
52.8
20.6
21.1
13.0
12.8
50
State Unemployment Rates (%)
PA
40
2007
2011
2012
2013
2014
4.4%
8.0%
7.9%
7.4%
5.8%
30
20
Source: Moody’s Analytics
10
18.9
18.9
2014A
2015F
0
M MWH
60
Residential
52.8
52.5
Commercial*
Industrial
*Includes Street Lighting
50
20.3
20.4
30
4.7
4.6
20
13.8
13.9
40
Gross Domestic Product Annualized Growth
(Seasonally Adjusted Annualized Rate)
PA
10
13.7
13.9
2014A
2015F
2007
2011
2012
2013
2014
1.6%
1.4%
1.2%
0.7%
0.3%
Source: Moody’s Analytics
0
PN
ME
PP
Gross Domestic Product, in 2009 dollars
($ billions)
WPP
Note: Forecasted sales assume normal weather.
Includes forecast for state energy efficiency mandates
(State Mandate 3.0% by 5/31/13, ~1.6M MWH. Incrementally ~1.1M
MWH by 5/31/16 ~1.1M)
PA
2007
2011
2012
2013
2014
$581
$593
$600
$604
$606
Source: Moody’s Analytics
FirstEnergy FactBook
Published May 1, 2015
40
Published May 1, 2015
41
Pennsylvania – Political Landscape
Governor
Governor
Thomas W. Wolf (D)
Current Term
Expires in 2019
Pennsylvania Public Utility Commission (PAPUC)
Commissioners
Robert F. Powelson, Chairman (R)
Current Term
Expires in 2019
John F. Coleman, Jr., Vice Chairman (R)
Expires in 2017
James H. Cawley (D)*
Expires in 2015
Pamela A. Witmer (R)
Expires in 2016
Gladys M. Brown (D)
Expires in 2018
* While Commissioner Cawley’s term officially expired on April 1, 2015, he may serve up to an additional 6 months
(October 1, 2015) if a new Commissioner is not yet nominated and confirmed.
FirstEnergy FactBook
21
FirstEnergy FactBook
Published May 1, 2015
Pennsylvania – Energy Efficiency
Pennsylvania
State Goals
Smart Grid
PA Act 129
By 5/31/2016 (1,090 GWH) – Phase II of Act 129
– ME +2.3% (338 GWH)
Energy Efficiency – PN +2.2% (319 GWH)
– PP +2.0% (96 GWH)
– WPP +1.6% (338 GWH)
Demand
Response
No peak demand reduction targets in Phase II,
6/2013 through 5/2016
Smart Meter
Smart Meter full deployment
 Mandatory deployment within
15 year depreciation cycle
Commission approval received June 5, 2014, on
the Revised Smart Meter Deployment Plan
Deployment began in July 2014 of 170,000 smart
meters in PP by the end of 2015 and nearly all PA
FE customers by mid-2019.
Cost Recovery for
Energy Efficiency
In place; annual energy efficiency rider
Compliance
On track to achieve 2016 EE targets
ME
($33M)
Distribution
Automation
$9
Volt / VAR Control
$5
Integrated Distributed
Energy Resource
Direct Load Control
Status
Smart Meter
Cross-cutting*
Technologies/
Programs
$19
■ Period of performance = 60 months
(June 2, 2010 – June 1, 2015)
■ Implementation of all programs
during 2014
■ All just and reasonable costs are
fully reimbursable via federal grant
and state approved riders (subject
to audit)
*Cross-cutting describes a project that includes
communications and control systems that support more
than one component of the smart grid
Published May 1, 2015
FirstEnergy FactBook
42
Pennsylvania – Smart Grid Modernization Initiative Update
■ Project Status: 99% Complete
■ Remaining Work
– Metrics & Benefits Reporting
■ $32M of $33M spent through 1Q 2015
Distribution Automation (DA) and
Volt/Var Control (VVC) Operational
Department of Energy
Agreement Terminates
DA & VVC Automatic
2Q
2013
3Q
2013
4Q
2013
1Q
2014
2Q
2014
3Q
2014
4Q
2014
2015
Metrics and Benefits Data
Collection Completed
FirstEnergy FactBook
Published May 1, 2015
43
22
FirstEnergy FactBook
Published May 1, 2015
Pennsylvania – Smart Meter Update
■ Commission Approval Received on June 5, 2014
– Order approves the Revised Smart Meter Deployment Plan
– Deployment began in July 2014
– Approximately 79,000 meters installed by PP through the end of Q1 2015
■ Revised Deployment Plan Timeframe
– 2014 - 2015: PP rolls out test program using 170,000 meters
– 2016 - 2019: Four-year deployment schedule to install approximately two million meters in
remaining Pennsylvania Operating Companies
■ Financial Impacts
– 20-Year Cost: $1.26B
– Deployment cost Included in Total Cost: $815M
– Estimated Operational Savings: $417M
–
–
–
–
Meter Reading:
Meter Services:
Contact Center:
Back Office:
$383M
$13M
$2M
$19M
■ Cost Recovery Mechanism: Smart Meter Technologies Charge (SMT-C)
– The orders in the base rate cases have established a baseline to measure savings that will result
from the deployment of smart meters
– PAPUC approved 2015 SMT-C rates which became effective January 1, 2015. The SMT-C will be
set to zero effective May 3, 2015, until the costs included in base rates are exceeded.
Published May 1, 2015
FirstEnergy FactBook
44
Pennsylvania – Smart Meter Update
Test and Validation:
170,000 Smart Meters
Begin Full Smart
Meter Deployment
~98.5% Smart
Meters Deployed
FE SMIP Filing
Operational Savings
Begin in 2016
Build Phase
2012
2013
2014
2015
2016
2017
2018
2019
2020 - 2025
Phase 2B / “Smart” (2014 – 2019)
PP Deployment
(July 2014)
PAPUC Approval
(June 2014)
Phase 2C* / “Smarter” (2017 – 2021)
PAPUC Order Received;
FE Revised SMIP Filing
Phase 2D* / “Smartest”
(2019 – 2025)
Post Grace Period:
New Construction and
Early Adopters Phase 2A
*Smarter and Smartest Phases are not
included in the Business Case
FirstEnergy FactBook
Published May 1, 2015
45
23
FirstEnergy FactBook
Published May 1, 2015
Pennsylvania – Regulatory Update
Final Approved Rate Case Summary1
Case Docket #
Capital
Structure2
ROE3
Met-Ed
Penelec
Penn Power
West Penn Power
R-2014-2428745
R-2014-2428743
R-2014-2428744
R-2014-2428742
50.00% Debt, 50.00% Equity 50.10% Debt, 49.90% Equity 49.90% Debt, 50.10% Equity 49.90% Debt, 50.10% Equity
5.21% Cost of Debt
5.72% Cost of Debt
6.12% Cost of Debt
5.38% Cost of Debt
Settled
Settled
Settled
Settled
Overall Return3
Settled
Settled
Settled
Settled
Percentage
Change Over
Revenues At
Existing Rates4
6.8%
6.6%
5.2%
7.0%
$90,000
$91,300
$17,000
$59,900
–
–
–
29,600
(700)
(500)
(1,100)
7,300
Included in Distribution
Included in Distribution
Included in Distribution
Included in Distribution
$89,300
$90,800
$15,900
$96,800
$56,200
$71,900
$13,000
$64,000
($ Thousands)
Distribution Base
Rates
USC Rider
DSS and HPS
Riders
Smart Meter
Annual Total
Revenue
Increase
Annual Pre-tax
Earnings Impact
1 Approved
by the PAPUC on April 9, 2015
2 Reflects filed debt liquidity and cost of debt
3 Settlements did not disclose these specific elements
4 Percentage was calculated based on total estimated revenue for the fully projected future test year consisting of distribution revenue as well as generation service
revenue, with the latter reflecting generation rates equivalent to the Companies’ prices for applicable default service
Settlements and supporting documents filed by ME, PN, PP, and WPP are available at www.puc.state.pa.us
FirstEnergy FactBook
Published May 1, 2015
46
Pennsylvania – Regulatory Update
■ WPP Universal Service Rider – makes the WPP Universal Service cost
recovery consistent with ME, PN, and PP
– Enables WPP to increase expenditures and enhance existing programs in response to
changes in economic conditions
– Rate filed annually on December 1
– Charged to residential customers only
■ Default Service Support (DSS)/Hourly Pricing Service (HPS) rider
changes – Uncollectibles normalized
– Update WPP DSS rider to include default service and purchase of receivable-related
uncollectible expense
– Collect industrial default service related uncollectibles through the HPS rider
■ Time-of-Use
– Elimination of time-of-use distribution rates (Rate Schedule Residential Time of Day) for
ME and PN
– Creation of Time-of-Use Riders for Residential Price-to-Compare charge for ME and PN
■ Storm Reserve Accounts established for non-extraordinary storms
– Enables each Company to defer storm-related expenses for future recovery
FirstEnergy FactBook
Published May 1, 2015
47
24
FirstEnergy FactBook
Published May 1, 2015
Pennsylvania – Regulatory Update
■ Met-Ed, Penelec, Penn Power and West Penn Power Default
Service Programs for June 2015 – May 2017
– Default Service Programs filed on November 3, 2013
– A settlement was reached with all intervening parties on all but one
issue
– Settlement Documents and Initial Briefs filed March 27, 2014, and
Reply Briefs filed April 10, 2014
– ALJ RD was issued May 7, 2014
– PAPUC approved settlement July 24, 2014
– Changes and new rates for Price to Compare Default Service
Riders and Default Service Support Riders become effective on
June 1, 2015
FirstEnergy FactBook
Published May 1, 2015
48
Pennsylvania – Procurement Schedule
ME Default Service Supply Plan • June 1, 2013 to May 31, 2015
Residential Full Requirements Tranche Procurement Schedule*
Delivery Period
Auction
Tranches Bid
Jan-13
12
Feb-13
12
Jan-14
12
6/1/13
11/30/13
12/1/13
5/31/14
6/1/14
11/30/14
12/1/14
5/31/15
24 months - $67.71 / MWH
12 months - $71.34 / MWH
12 months - $63.24 / MWH
Commercial Full Requirements Tranche Procurement Schedule
Delivery Period
Auction
Tranches Bid
Jan-13
11
Feb-13
12
Sep-13
11
Jan-14
12
Sep-14
11
6/1/13
11/30/13
12/1/13
5/31/14
6/1/14
11/30/14
12/1/14
5/31/15
6 months - $66.34 / MWH
12 months - $69.16 / MWH
12 months - $63.49 / MWH
12 months - $63.09 / MWH
6 months - $80.23 / MWH
Hourly Pricing Service Tranche Procurement Schedule
Delivery Period
Auction
Tranches Bid
Sep-13
11
6/1/13
11/30/13
12/1/13
5/31/14
6/1/14
11/30/14
12/1/14
5/31/15
18 months - $18.46 / MWH
* Schedule does not reflect four additional existing fixed-block, energy-only tranches procured during the January 2010 auction which terminate on May 31, 2015
FirstEnergy FactBook
Published May 1, 2015
49
25
FirstEnergy FactBook
Published May 1, 2015
Pennsylvania – Procurement Schedule
ME Default Service Supply Plan • June 1, 2015 to May 31, 2017
Auction Month
October 2015
January 2016
April 2016
4
4
4
4
5
4
4
4
5
Auction Month
Tranches
October 2014
January 2015
April 2015
October 2014
January 2015
2
2
2
2
3
April 2015
June 2015
October 2015
6/1/15 to
8/31/15
Tranches
1
1
3
Residential Full Requirements Tranche Procurement Schedule
9/1/15 to
12/1/15 to
3/1/16 to
6/1/16 to
9/1/16 to
12/1/16 to
11/30/15
2/29/16
5/31/16
8/31/16
11/30/16
2/28/17
12-Months - $77.89 / MWH
24-Months - $76.82 / MWH
12-Months - $65.74 / MWH
24-Months - $66.03 / MWH
12-Months - $66.53 / MWH
24-Months - $66.44 / MWH
12-Months
12-Months
12-Months
Commercial Full Requirements Tranche Procurement Schedule
9/1/15 to
12/1/15 to
3/1/16 to
6/1/16 to
9/1/16 to
11/30/15
2/29/16
5/31/16
8/31/16
11/30/16
12-Months - $86.56
24-Months - $89.56
12-Months - $66.09 / MWH
24-Months - $66.53 / MWH
3-Months $67.20 / MWH
12-Months - $65.03 / MWH
24-Months - $65.15 / MWH
3-Months
6/1/15 to
8/31/15
12-Months
12-Months
3-Months
3
1
June 2016
12-Months
3-Months
3
October 2016
3
January 2017
3
Auction Month
Tranches
January 2015
8
January 2016
8
3/1/17 to
5/31/17
3-Months
3
2
April 2016
12/1/16 to
2/28/17
3-Months
3
2
January 2016
3/1/17 to
5/31/17
3-Months
3-Months
6/1/15 to
8/31/15
Hourly Price Service Tranche Procurement Schedule
9/1/15 to
12/1/15 to
3/1/16 to
6/1/16 to
11/30/15
2/29/16
5/31/16
8/31/16
9/1/16 to
11/30/16
3/1/17 to
5/31/17
12/1/16 to
2/28/17
12-Months - $30.50 / MWH
12-Months
Published May 1, 2015
FirstEnergy FactBook
50
Pennsylvania – Procurement Schedule
PN Default Service Supply Plan • June 1, 2013 to May 31, 2015
Residential Full Requirements Tranche Procurement Schedule*
Delivery Period
Auction
Tranches Bid
Jan-13
9
Feb-13
9
Jan-14
9
6/1/13
11/30/13
12/1/13
5/31/14
6/1/14
11/30/14
12/1/14
5/31/15
24 months – $61.14 / MWH
12 months - $64.39 / MWH
12 months - $58.36 / MWH
Commercial Full Requirements Tranche Procurement Schedule
Delivery Period
Auction
Tranches Bid
Jan-13
10
Feb-13
10
Sep-13
10
Jan-14
10
Sep-14
10
6/1/13
11/30/13
12/1/13
5/31/14
6/1/14
11/30/14
12/1/14
5/31/15
6 months - $63.05 / MWH
12 months – $65.18 / MWH
12 months – $60.89 / MWH
12 months - $60.92 / MWH
6 months - $74.79 / MWH
Hourly Pricing Service Tranche Procurement Schedule
Delivery Period
Auction
Tranches Bid
Sep-13
11
6/1/13
11/30/13
12/1/13
5/31/14
6/1/14
11/30/14
12/1/14
5/31/15
18 months - $12.99 / MWH
* Schedule does not reflect four additional existing fixed-block, energy-only tranches procured during the January 2010 auction which terminate on May 31, 2015.
FirstEnergy FactBook
Published May 1, 2015
51
26
FirstEnergy FactBook
Published May 1, 2015
Pennsylvania – Procurement Schedule
PN Default Service Supply Plan • June 1, 2015 to May 31, 2017
Auction Month
October 2015
January 2016
April 2016
3
3
3
3
3
3
3
3
3
Auction Month
Tranches
October 2014
January 2015
April 2015
October 2014
January 2015
2
2
2
2
5
April 2015
1
1
June 2015
5
October 2015
6/1/15 to
8/31/15
Tranches
Residential Full Requirements Tranche Procurement Schedule
9/1/15 to
12/1/15 to
3/1/16 to
6/1/16 to
9/1/16 to
12/1/16 to
11/30/15
2/29/16
5/31/16
8/31/16
11/30/16
2/28/17
12-Months - $73.24 / MWH
24-Months - $73.61 / MWH
12-Months - $63.47 / MWH
24-Months - $63.75 / MWH
12-Months - $62.37 / MWH
24-Months - $63.16 / MWH
12-Months
12-Months
12-Months
Commercial Full Requirements Tranche Procurement Schedule
9/1/15 to
12/1/15 to
3/1/16 to
6/1/16 to
9/1/16 to
11/30/15
2/29/16
5/31/16
8/31/16
11/30/16
12-Months - $86.67
24-Months - $80.13
12-Months - $63.69 / MWH
24-Months - $64.34 / MWH
3-Months $66.89 / MWH
12-Months - $64.12 / MWH
24-Months - $62.25 / MWH
3-Months
6/1/15 to
8/31/15
12-Months
3-Months
5
2
12-Months
3-Months
5
April 2016
1
June 2016
12-Months
3-Months
5
October 2016
5
January 2017
5
Auction Month
Tranches
January 2015
9
January 2016
9
3/1/17 to
5/31/17
3-Months
5
2
January 2016
12/1/16 to
2/28/17
3/1/17 to
5/31/17
3-Months
3-Months
6/1/15 to
8/31/15
Hourly Price Service Tranche Procurement Schedule
9/1/15 to
12/1/15 to
3/1/16 to
6/1/16 to
11/30/15
2/29/16
5/31/16
8/31/16
9/1/16 to
11/30/16
12/1/16 to
2/28/17
3/1/17 to
5/31/17
12-Months - $17.50 / MWH
12-Months
Published May 1, 2015
FirstEnergy FactBook
52
Pennsylvania – Procurement Schedule
PP Default Service Supply Plan • June 1, 2013 to May 31, 2015
Residential Full Requirements Tranche Procurement Schedule*
Delivery Period
Auction
Tranches Bid
Jan-13
3
Feb-13
3
Jan-14
3
6/1/13
11/30/13
12/1/13
5/31/14
6/1/14
11/30/14
12/1/14
5/31/15
24 months - $52.22 / MWH
12 months - $45.45 / MWH
12 months - $58.04 / MWH
Commercial Full Requirements Tranche Procurement Schedule
Delivery Period
Auction
Tranches Bid
Jan-13
3
Feb-13
4
Sep-13
3
Jan-14
4
Sep-14
3
6/1/13
11/30/13
12/1/13
5/31/14
6/1/14
11/30/14
12/1/14
5/31/15
6 months - $47.19 / MWH
12 months – $48.19 / MWH
12 months – $55.72 / MWH
12 months - $63.42 / MWH
6 months - $73.73 / MWH
Hourly Pricing Service Tranche Procurement Schedule
Delivery Period
Auction
Tranches Bid
Sep-13
3
6/1/13
11/30/13
12/1/13
5/31/14
6/1/14
11/30/14
12/1/14
5/31/15
18 months - $10.22 / MWH
* Schedule does not reflect four additional existing fixed-block, energy-only tranches procured during the January 2010 auction which terminate on May 31, 2015
FirstEnergy FactBook
Published May 1, 2015
53
27
FirstEnergy FactBook
Published May 1, 2015
Pennsylvania – Procurement Schedule
PP Default Service Supply Plan • June 1, 2015 to May 31, 2017
Auction Month
October 2015
January 2016
April 2016
1
1
1
1
1
1
1
1
1
Auction Month
Tranches
October 2014
January 2015
April 2015
October 2014
January 2015
1
1
1
1
1
April 2015
June 2015
October 2015
6/1/15 to
8/31/15
Tranches
1
1
1
Residential Full Requirements Tranche Procurement Schedule
9/1/15 to
12/1/15 to
3/1/16 to
6/1/16 to
9/1/16 to
12/1/16 to
11/30/15
2/29/16
5/31/16
8/31/16
11/30/16
2/28/17
12-Months - $85.15 / MWH
24-Months - $78.47 / MWH
12-Months - $74.16 / MWH
24-Months - $72.32 / MWH
12-Months - $77.45 / MWH
24-Months - $69.93 / MWH
12-Months
12-Months
12-Months
Commercial Full Requirements Tranche Procurement Schedule
9/1/15 to
12/1/15 to
3/1/16 to
6/1/16 to
9/1/16 to
11/30/15
2/29/16
5/31/16
8/31/16
11/30/16
12-Months - $89.65
24-Months - $83.19
12-Months - $82.87 / MWH
24-Months - $78.74 / MWH
3-Months $87.50 / MWH
12-Months - $81.67 / MWH
24-Months - $77.00 / MWH
3-Months
6/1/15 to
8/31/15
12-Months
3-Months
1
1
April 2016
12-Months
3-Months
1
1
June 2016
12-Months
3-Months
1
October 2016
1
January 2017
1
Auction Month
Tranches
January 2015
2
January 2016
2
3/1/17 to
5/31/17
3-Months
1
1
January 2016
12/1/16 to
2/28/17
3/1/17 to
5/31/17
3-Months
3-Months
6/1/15 to
8/31/15
Hourly Price Service Tranche Procurement Schedule
9/1/15 to
12/1/15 to
3/1/16 to
6/1/16 to
11/30/15
2/29/16
5/31/16
8/31/16
9/1/16 to
11/30/16
12/1/16 to
2/28/17
3/1/17 to
5/31/17
12-Months - $25.95 / MWH
12-Months
Published May 1, 2015
FirstEnergy FactBook
54
Pennsylvania – Procurement Schedule
WPP Default Service Supply Plan • June 1, 2013 to May 31, 2015
Residential Full Requirements Tranche Procurement Schedule
Delivery Period
Auction
Tranches Bid
Jan-13
15
Feb-13
15
Jan-14
15
6/1/13
11/30/13
12/1/13
5/31/14
6/1/14
11/30/14
12/1/14
5/31/15
24 months - $51.04 / MWH
12 months - $46.53 / MWH
12 months - $57.36 / MWH
Commercial Full Requirements Tranche Procurement Schedule
Delivery Period
Auction
Tranches Bid
Jan-13
9
Feb-13
10
Sep-13
9
Jan-14
10
Sep-14
9
6/1/13
11/30/13
12/1/13
5/31/14
6/1/14
11/30/14
12/1/14
5/31/15
6 months - $45.05 / MWH
12 months - $45.92 / MWH
12 months - $49.46 / MWH
12 months - $57.29 / MWH
6 months - $68.99 / MWH
Industrial Hourly Pricing Service Tranche Procurement Schedule
Delivery Period
Auction
Tranches Bid
Sep-13
12
6/1/13
11/30/13
12/1/13
5/31/14
6/1/14
11/30/14
12/1/14
5/31/15
18 months - $5.68 / MWH
FirstEnergy FactBook
Published May 1, 2015
55
28
FirstEnergy FactBook
Published May 1, 2015
Pennsylvania – Procurement Schedule
WPP Default Service Supply Plan • June 1, 2015 to May 31, 2017
Auction Month
Tranches
October 2015
January 2016
April 2016
4
4
5
5
5
5
4
5
5
Auction Month
Tranches
October 2014
January 2015
April 2015
October 2014
January 2015
3
3
3
3
4
April 2015
June 2015
October 2015
1
1
4
6/1/15 to
8/31/15
Residential Full Requirements Tranche Procurement Schedule
9/1/15 to
12/1/15 to
3/1/16 to
6/1/16 to
9/1/16 to
12/1/16 to
11/30/15
2/29/16
5/31/16
8/31/16
11/30/16
2/28/17
12-Months - $70.22 / MWH
24-Months - $70.09 / MWH
12-Months - $59.05 / MWH
24-Months - $57.93 / MWH
12-Months – 61.06 / MWH
24-Months - $60.11 / MWH
12-Months
12-Months
12-Months
Commercial Full Requirements Tranche Procurement Schedule
9/1/15 to
12/1/15 to
3/1/16 to
6/1/16 to
9/1/16 to
11/30/15
2/29/16
5/31/16
8/31/16
11/30/16
12-Months - $75.73
24-Months - $74.46
12-Months - $60.52 / MWH
24-Months - $62.00 / MWH
3-Months $61.56 / MWH
12-Months - $59.68 / MWH
24-Months - $59.79 / MWH
3-Months
6/1/15 to
8/31/15
12-Months
12-Months
3-Months
4
3
June 2016
12-Months
3-Months
4
October 2016
4
January 2017
4
3/1/17 to
5/31/17
3-Months
4
2
April 2016
12/1/16 to
2/28/17
3-Months
4
2
January 2016
3/1/17 to
5/31/17
3-Months
3-Months
Auction Month
Tranches
January 2015
13
January 2016
13
6/1/15 to
8/31/15
Hourly Price Service Tranche Procurement Schedule
9/1/15 to
12/1/15 to
3/1/16 to
6/1/16 to
11/30/15
2/29/16
5/31/16
8/31/16
12-Months - $14.75 / MWH
9/1/16 to
11/30/16
3/1/17 to
5/31/17
12/1/16 to
2/28/17
12-Months
Published May 1, 2015
FirstEnergy FactBook
56
Pennsylvania – Long-Term Debt Schedules
Company
Type
First Mortgage Bond
Penn Power
First Mortgage Bond
CUSIP
Interest
Rate
Maturity
Amount
Outstanding
9.74%
11/1/2019
$4,903,000
6.09%
6/30/2022
$100,000,000
Private
Placement
Private
Placement
PP Total
Penelec
$104,903,000
Senior Note
708696BU2
6.05%
9/1/2017
$300,000,000
Senior Note
708696BM0
6.625%
4/1/2019
$125,000,000
Senior Note
708696BW8
5.2%
4/1/2020
$250,000,000
Senior Note
708696BX6
4.15%
4/15/2025
$200,000,000
Senior Note
708696BV0
6.15%
10/1/2038
$250,000,000
PN Total
$1,125,000,000
As of March 31, 2015
FirstEnergy FactBook
Published May 1, 2015
57
29
FirstEnergy FactBook
Published May 1, 2015
Pennsylvania – Long-Term Debt Schedules
Company
Type
CUSIP
Interest
Rate
Maturity
Amount
Outstanding
Senior Note
591894BX7
7.7%
1/15/2019
$300,000,000
Senior Note
591894BY5
3.5%
3/15/2023
$300,000,000
Senior Note
591894CB4
4.0%
4/15/2025
$250,000,000
Met-Ed
ME Total
West Penn
Power
$850,000,000
First Mortgage Bond
955278BG0
5.875%
8/15/2016
$145,000,000
First Mortgage Bond
955278BH8
5.95%
12/15/2017
$275,000,000
First Mortgage Bond
Private
Placement
3.34%
4/15/2022
$100,000,000
WPP Total
$520,000,000
As of March 31, 2015
FirstEnergy FactBook
Published May 1, 2015
58
30
FirstEnergy FactBook
Published May 1, 2015
Creating Value for Investors
New Jersey Operations
59
Published May 1, 2015
FirstEnergy FactBook
New Jersey – Customer Data
Major Metropolitan Areas
2014 Total Customers (thousands)
JCP&L
1,103
Monmouth County
(Middleton Township)
631
Ocean County (Lakewood
Township)
578
Morris County
(Parsippany)
493
Somerset County
(Franklin Township)
Typical Bill Comparison*
New Jersey
Population
(thousands)
$/Month
JCP&L
$136.62
Statewide Avg. Bill
$164.56
324
Total State of New Jersey
8,804
Source: U.S. Census Bureau (2010)
Principal Industries Served**
* Typical bills are based on 1,000 kWh of residential usage.
Billing amounts sourced from the EEI Typical Bills and Average
Rates Report as of July 1, 2014. New Jersey rates represent
POLR bundled residential rates
Chemical
Primary and Fabricated Metals
Plastic and Rubber
** Based on kWh sales
As of December 31, 2014
FirstEnergy FactBook
Published May 1, 2015
60
31
FirstEnergy FactBook
Published May 1, 2015
New Jersey – Distribution Sales
State Unemployment Rates (%)
NJ
2007
2011
2012
2013
2014
4.3%
9.3%
9.3%
8.2%
6.7%
Source: Moody’s Analytics
M MWH
20
Gross Domestic Product Annualized Growth
15
(Seasonally Adjusted Annualized Rate)
NJ
2007
2011
2012
2013
2014
1.3%
-0.5%
2.6%
1.1%
0.3%
20.8
21.1
2.3
2.3
9.2
9.3
9.3
9.5
25
10
5
Source: Moody’s Analytics
0
2014A
Gross Domestic Product, in 2009 dollars
($ billions)
Residential
2015F
Commercial*
Industrial
*Includes Street Lighting
NJ
2007
2011
2012
2013
2014
$511
$491
$503
$509
$511
Source: Moody’s Analytics
Note: Forecasted sales assume normal weather. Includes forecast
for state energy efficiency mandates. (NJ Mandate state goal
of 20% usage reduction by 2020).
FirstEnergy FactBook
Published May 1, 2015
61
Published May 1, 2015
62
New Jersey – Political Landscape
Governor
Governor
Christopher J. Christie (R)
Current Term
Expires in 2018
New Jersey Board of Public Utilities (BPU)
Commissioners
Current Term
President Richard S. Mroz (R)*
Expires in 2015
Dianne Solomon (R)
Expires in 2018
Joseph L. Fiordaliso (D)**
Expires in 2019
Upendra Chivukula (D)
Expires in 2020
Mary-Anna Holden (R)
Expires in 2017
*Term expired in March 2015. Re-nomination is expected.
**Pending Senate confirmation
FirstEnergy FactBook
32
FirstEnergy FactBook
Published May 1, 2015
New Jersey – Regulatory Update
JCP&L Distribution Rate Case/Regulatory Proceedings
■ November 30, 2012: Distribution Rate Case filed
■ January 23, 2013: BPU established a generic proceeding to review the consolidated
tax adjustment policy
■ February 22, 2013: Filing updated to include Hurricane Sandy costs
■ March 20, 2013: BPU established a generic proceeding to review prudency of storm
costs for 2011 and 2012
■ April 4, 2013: JCP&L filed a Motion for Reconsideration to leave storm costs in the
base rate case
■ May 31, 2013: BPU issued "Clarifying Order" stating rate treatment for 2011 Storm
costs would be applied in JCP&L's existing rate case. A Phase II of the rate case or
some other rate treatment would be utilized relating to the 2012 Storm costs
■ June 14, 2013: Filed update to incorporate the results of the BPU-Ordered
Depreciation Study, the amended Cash Working Capital Testimony, and removed 2012
storm costs and other revisions identified during discovery
■ August 7, 2013: Rebuttal testimony filed and reflected a revision to the proposed ROE
■ September 12, 2013: Evidentiary hearings continued through November
FirstEnergy FactBook
Published May 1, 2015
63
New Jersey – Regulatory Update
JCP&L Distribution Rate Case/Regulatory Proceedings (Continued)
■ January 27, 2014: Briefs submitted by parties
■ February 24, 2014: Reply briefs submitted
■ February 24, 2014: JCP&L, BPU Staff, Division of Rate Counsel entered into a stipulated agreement in the generic
storm proceedings to allow recovery of $736M out of $744M for 2011 and 2012 significant weather events
– $156M of 2011 costs to be recovered in the pending JCP&L rate case: $74M Capital, $82M Deferred O&M
– Recovery mechanism and timing of 2012 costs of $580M is to be determined: $333M Capital, $247M Deferred O&M
■ March 19, 2014: Generic storm proceeding settlement approved
■ May 5, 2014: JCP&L filed updated schedules to reflect the results of the generic storm cost proceeding and revised
the debt rate to 5.93%
■ June 18, 2014: BPU Staff proposed that the current Consolidated Tax Adjustment (CTA) policy remain in effect
except as amended by the following:
– Calculation would look back 5 years from the beginning of the test year
– Allocation of the calculated savings would be 75% to the company and 25% ratepayers; and
– Transmission assets of the EDCs would not be included in the calculation of the CTA
■ June 30, 2014: ALJ closed record in base rate case
■ October, 22, 2014: BPU issued an order approving Staff’s CTA proposal. Following an initial decision of the
Administrative Law Judge (ALJ), the BPU would reopen the record in JCP&L’s pending base rate case for the limited
purpose of adding a CTA calculation reflecting this modified policy and allow parties the opportunity to comment.
■ January 8, 2015: ALJ filed the Initial Decision
■ January 30, 2015: BPU Staff submitted a calculation of the CTA for the rate case, with comments due
February 19, 2015
■ February 5, 2015: Exceptions to ALJ’s initial decision filed
■ February 19, 2015: Reply exceptions due
FirstEnergy FactBook
Published May 1, 2015
64
33
FirstEnergy FactBook
Published May 1, 2015
New Jersey – Regulatory Update
JCP&L Distribution Rate Case/Regulatory Proceedings (Continued)
■ February 11, 2015: BPU approved a 45-day extension to render a final decision by April 8, 2015
■ March 26, 2015: BPU issued a final order in the Base Rate Case with rates effective April 1,
2015; Final order issued in the Generic Storm Proceeding for recovery of the 2012 storm costs
as part of this Base Rate Case; An adjustment for CTA was also included.
JCP&L
November 30,
20121
JCP&L
August 7, 20131
JCP&L
May 5, 20141
Initial Filing
Revised ROE
Revised Debt
Rate to 5.93%
$31M, 1.4%*
$11M, 0.50%*
Debt/Equity Ratio
46% / 54%
Return on Equity
Rate Base
Rate
Increase/(Decrease)
1Filing
ALJ's Initial
Decision
January 8, 2015
BPU Decision
March 18, 2015
Meeting
$9.1M, 0.40%*
($107.5M),
(4.84%)*
($34.3M), (1.54%)*
46% / 54%
46% / 54%
50% / 50%
11.53%
11.00%
11.00%
9.75%
$2.040B
$2.024B
$2.021B
$1.901B
50% / 50%
9.75%
$2.089B
includes 2011 storm costs and does not include a CTA adjustment.
*Residential Rate Impact
FirstEnergy FactBook
65
Published May 1, 2015
New Jersey – Energy Efficiency
New Jersey
State Goals
Energy Master Plan (EMP)
Energy Efficiency
2011 modified EMP goal of 20% usage
reduction by 2020 (State Goal), subject
to modification
Demand Response
17% reduction by 2020 of 2011 PJM
Demand Forecast (State Goal)
Smart Grid
Smart Grid DR program 2011. DOE
funded circuit automation pilot for 2014
Cost Recovery for
Energy Efficiency
In place; annual energy efficiency rider
Compliance
 Current EE programs run by the
State’s Office of Clean Energy
Smart Grid
Cross-cutting*
Technologies/
Programs
JCP&L
($15M)
Distribution Automation
Integrated Distributed Energy
Resource
Direct Load Control
$1
$14
■ Period of performance = 60 months
(June 2, 2010 – June 1, 2015)
■ Programs were operational during
2014
■ All just and reasonable costs are
fully reimbursable via federal grant
and state approved riders (subject
to audit)
*Cross-cutting describes a project that includes communications
and control systems that support more than one component of
the smart grid
FirstEnergy FactBook
Published May 1, 2015
66
34
FirstEnergy FactBook
Published May 1, 2015
New Jersey – Smart Grid Modernization Initiative Update
■ Project Status: 99% Complete
■ Remaining Work
– Distribution Automation (DA) Pilot
– Metrics & Benefits Reporting
■ $15M spent through 1Q 2015
DA Pilot (NJ)
Department of Energy
Agreement Terminates
DA Pilot Operation
2Q
2013
3Q
2013
4Q
2013
1Q
2014
2Q
2014
3Q
2014
4Q
2014
2015
Metrics and Benefits Data
Collection Completed
2014 Summer Integrated Distribution
Energy Resource Program
Published May 1, 2015
FirstEnergy FactBook
67
New Jersey – Procurement Schedule
JCP&L Generation Service Supply Plan
State-wide procurement process
Approximately 33.3% load annually - 100 MW Fixed Price Full Requirements Tranches – Residential & Small Commercial
Delivery Period
Auction
Tranches Bid
Feb-14
15
Feb-15
20
Feb-16
18
June 2014
June 2015
June 2016
May 2017
May 2018
May 2019
36 months - $84.44 / MWH
36 months - $80.42 / MWH
36 months
100% load annually - 75 MW Hourly Priced Full Requirements Tranches – Large Commercial Industrial
Delivery Period
Auction
Tranches Bid
June 2014 – May 2015
Feb-14
13
12 months - $254.79 / MW Day
Feb-15
16
Feb-16
13
June 2015 – May 2016
June 2016 – May 2017
12 months - $248.41 / MW Day
12 months
FirstEnergy FactBook
Published May 1, 2015
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35
FirstEnergy FactBook
Published May 1, 2015
New Jersey – Long-Term Debt Schedules
Company
JCP&L
CUSIP
Interest
Rate
Maturity
Amount
Outstanding
Senior Note
476556CM5
5.625%
5/1/2016
$300,000,000
Senior Note
476556CW3
5.65%
6/1/2017
$250,000,000
Senior Note
476556CK9
4.8%
6/15/2018
$150,000,000
Senior Note
476556DA0
7.35%
2/1/2019
$300,000,000
Senior Note
476556DB8
4.7%
4/1/2024
$500,000,000
Senior Note
476556CP8
6.4%
5/15/2036
$200,000,000
Senior Note
476556CT0
6.15%
6/1/2037
$300,000,000
Transition Bond
47214TAD1
6.16%
6/5/2017*
$66,166,756
Transition Bond
47215BAC1
5.52%
6/5/2018*
$41,908,224
Transition Bond
47215BAD9
5.61%
6/5/2021*
$51,139,000
Type
JCP&L Total
JCP&L Transition
Funding LLC
JCP&L Transition Funding LLC Total
$2,000,000,000
$159,213,980
* Expected Final Maturity Date
As of March 31, 2015
FirstEnergy FactBook
Published May 1, 2015
69
36
FirstEnergy FactBook
Published May 1, 2015
Creating Value for Investors
West Virginia/Maryland Operations
FirstEnergy FactBook
70
Published May 1, 2015
West Virginia/Maryland – Customer Data
2014 Total Customers (thousands)
MP
389
PE
397
Total
786
Major Metropolitan
Areas
Typical Bill Comparison*
West Virginia/Maryland
MP/PE-WV
PE-MD
$/Month
$92.62
$107.03
WV Statewide Avg. Bill
$93.20
MD Statewide Avg. Bill
$132.17
* Typical bills are based on 1,000 kWh of residential usage.
Billing amounts sourced from the EEI Typical Bills and
Average Rates Report as of July 1, 2014. MD/WV rates
represent POLR bundled residential rates
Principal Industries Served**
Chemical
Coal Mining
Non-Metallic Minerals
Primary and Fabricated Metals
Oil and Gas Extractions
** Based on kWh sales
Population
(thousands)
Berkeley County
(Martinsburg)
105
Monongalia County
(Morgantown)
97
Wood County
(Parkersburg)
Total State of
West Virginia
Major Metropolitan
Areas
Frederick County
Washington County
(Hagerstown)
Allegany County
(Cumberland)
Total State of
Maryland
87
1,854
Population
(thousands)
234
148
75
5,788
Source: U.S. Census Bureau (2010)
As of December 31, 2014
FirstEnergy FactBook
Published May 1, 2015
71
37
FirstEnergy FactBook
Published May 1, 2015
West Virginia/Maryland – Distribution Sales
MP
M MWH
11.9
11.4
14
State Unemployment Rates
12
10
2007
2011
2012
2013
2014
WV
4.2%
7.9%
7.3%
6.5%
6.3%
6
MD
3.4%
7.3%
6.9%
6.6%
5.9%
4
4.8
5.4
2.8
2.8
3.8
3.7
2014A
2015F
8
2
Source: Moody’s Analytics
0
PE
M MWH
12
10
10.6
10.6
2.4
2.4
3.0
3.0
Residential Commercial Industrial
Note: Forecasted sales assume normal weather. Includes forecast for state
energy efficiency mandates. (WV Mandate 0.5% of 2009 sales by 12/31/16,
~0.1M MWH. Plus incremental 0.5% of 2013 Sales by May 2018)
Gross Domestic Product Annualized Growth
(Seasonally Adjusted Annualized Rate)
8
6
WV
MD
4
5.2
2
2007
-0.4%
1.6%
2011
2.5%
1.7%
2012
-1.4%
1.2%
2013
5.1%
0.0%
2014
-0.2%
1.1%
Source: Moody’s Analytics
5.2
Gross Domestic Product, in 2009 dollars
0
2014A
Residential
Commercial
($ billions)
2015F
Industrial
WV
MD
Note: Forecasted sales assume normal weather.
Includes forecast for state energy efficiency mandates.
(MD Mandate 10% per capita by 12/31/15, ~0.4M MWH)
2007
$62
$303
2011
$66
$318
2012
$65
$322
2013
$69
$322
2014
$68
$326
Source: Moody’s Analytics
Published May 1, 2015
FirstEnergy FactBook
72
West Virginia/Maryland – Political Landscape
West Virginia
Maryland
Governor
Governor
Governor
Current Term
Governor
Current Term
Earl Ray Tomblin (D)
Expires in 2017
Lawrence J. Hogan (R)
Expires in 2019
Public Service Commission of West
Virginia (WV PSC)
Maryland Public Service Commission
(PSC)
Current Term
Current Term
Commissioners
Michael A. Albert, Chairman (R)
Expires in 2019
W. Kevin Hughes, Chairman (D)
Expires in 2018
Brooks F. McCabe (D)
Expires in 2015*
Harold D. Williams (D)
Expires in 2017
Vacant
Expires in 2015*
Lawrence Brenner (D)
Expires in 2015*
Commissioners
Kelly Speakes-Backman (D)
Anne E. Hoskins (D)
Until Reappointed or
Replaced**
Expires in 2016
* Term expires on June 30
**Term expired June 30, 2014, but continues to serve pending replacement.
FirstEnergy FactBook
Published May 1, 2015
73
38
FirstEnergy FactBook
Published May 1, 2015
West Virginia – Regulatory Update
Rate Case
■ April 30, 2014: Base Rate Case Filed (Case # 14-0702-E-42T)
– $95.7M (9.27%) base rate increase (2013 historic test year), inclusive of depreciation rate increase
– $144.1M (14.0%) overall increase including vegetation management plan surcharge
– 11% return on equity
– Depreciation case filed concurrently ($17M reflected in overall increase)
■ June 13, 2014: Amendment to Base Rate Case
– Amendment filed due to WV PSC order requiring MP and PE-WV to begin reading customer meters on a monthly basis no
later than July 1, 2015 (i.e., convert bimonthly meter reads to monthly meter reads)
– Annual incremental increase of $7.5M
– Amended rate impact: $103.2M (9.99%) base rate increase, inclusive of depreciation rate increase
– $151.6M (14.7%) overall increase including vegetation management program and monthly meter reading
■ November 3, 2014: Joint Settlement filed with the WV PSC
– Hearing on the joint settlement held on November 7, 2014
– Joint settlement includes:
–
–
–
–
–
–
–
–
$15M (1.43%) base rate increase, includes moving Harrison surcharge into base rates
Vegetation Management Surcharge of $48M (4.52%) in 2015
Vegetation Management Surcharge along with the base rate increase results in an overall increase of $63M (5.95%)
Collection of $46M of 2012 storm costs, amortized over 5 years
Depreciation rates remain unchanged from current value
Base Rate Change
$ 124.3M
Delay in ENEC rate change until Feb 25, 2015
Deferral of 2016-2017 MATS capital costs
Black box settlement does not provide ROE and income tax rate in
base rates
■ February 3, 2015: WVPSC approved joint settlement without modification
■ February 25, 2015: Effective date of new rates and surcharge
FirstEnergy FactBook
Elimination of Harrison
Surcharge
Vegetation Management
Surcharge
Total Settlement Increase
$ (109.3)
$
47.6
$ 62.6M
Published May 1, 2015
74
West Virginia – Regulatory Update
West Virginia Vegetation Maintenance Program & MATS Compliance
■ Vegetation Management Surcharge
– Permits timely recovery of cycle-based, end-to-end vegetation management plan
approved by the WV PSC on April 14, 2014
– Reconcilable surcharge to recover 100% of vegetation management O&M and
capital costs between base rate cases
– Deferral of incremental O&M costs (incurred from April 14, 2014 PSC order date
through February 25, 2015 effective date of new rates) to be included in September
2015 reconciliation filing for rates effective January 1, 2016
– Includes $15M O&M previously in base rates
■ MATS Compliance Capital Recovery
– New base rates include collection of MATS compliance capital projects placed in
service by December 31, 2015
– Establishes regulatory asset for MATS compliance capital projects placed in service
during 2016-2017
– Recovery of the regulatory asset expected in the next base rate case
FirstEnergy FactBook
Published May 1, 2015
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39
FirstEnergy FactBook
Published May 1, 2015
Maryland – Procurement Schedule
Delivery Period **
Load Type
Tranches Bid *
Auction Date
June 2014 - May 2015
1
Residential
June 2015 - May 2016
June 2016 - May 2017
12 Months
October 2013
1
24 Months
2
Residential
12 Months
January 2014
2
24 Months
1
Residential
12 Months
April 2014
1
24 Months
1
Residential
12 Months
June 2014
1
24 Months
Delivery Period **
Load Type
Tranches Bid *
Auction Date
Small C&I
1
October 2013
June 2014 - May 2016
24 Months
Small C&I
1
January 2014
24 Months
Load Type
Tranches Bid *
Auction Date
Dec 2013 –
Feb 2014
Medium C&I
3
October 2013
3 Months
Medium C&I
3
January 2014
Medium C&I
3
April 2014
Medium C&I
3
June 2014
Delivery Period **
March 2014 –
May 2014
June 2014 –
Aug 2014
Sept 2014 –
Nov 2014
3 Months
3 Months
3 Months
*All tranches are for full requirements service.
**The Maryland PSC does not release bid or winning prices. However, a list of bidders who submitted bids and a list of winning bidders can be found at
https://www.firstenergycorp.com/content/fecorp/upp/md/power_procurements/2014sosrfp/archive.html
Published May 1, 2015
FirstEnergy FactBook
76
Maryland/West Virginia – Energy Efficiency
State Goals
Maryland
West Virginia
EmPower MD
Base Rate Case and Merger
Settlements
10.0% per capita by 12/31/2015 (415 GWh)
Energy Efficiency
By 12/31/2017 (673 GWh cumulative)1
0.5% of 2009 Sales by 12/31/2016
(67 GWH)
Plus incremental 0.5% of 2013 Sales by May
2018 (71 GWH)
15.0% per capita by 12/31/2015 (21 MW)
Demand Response
0.5% of 2009 Demand by 12/31/2016 (14 MW)
By 12/31/2017 (96 MW cumulative) 1
Smart Meter
No state smart meter requirement
No state smart meter requirement
Cost Recovery for
Energy Efficiency
In place – 5 year amortization schedule
with carrying costs and annual
reconciliation
In place – annual energy efficiency rider
Compliance
Preliminary data indicates 2015 EE/DR
targets achieved
On track to achieve 2015-2017 EE/DR
targets
On track to achieve EE/DR 2016 targets
112/31/2017
savings estimates are based on Potomac Edison’s approved 2015-2017 EE/PDR Plan
FirstEnergy FactBook
Published May 1, 2015
77
40
FirstEnergy FactBook
Published May 1, 2015
West Virginia/Maryland – Long-Term Debt Schedules
Company
Mon Power
Type
CUSIP
Interest
Rate
Maturity
Amount
Outstanding
Pollution Control
Note*
41524CAU8
5.5%
10/15/2037
$73,500,000
First Mortgage Bond
610202BK8
5.375%
10/15/2015
$70,000,000
First Mortgage Bond
610202BL6
5.7%
3/15/2017
$150,000,000
First Mortgage Bond
610202BN2
4.1%
4/15/2024
$400,000,000
First Mortgage Bond
610202BP7
5.4%
12/15/2043
$600,000,000
553214AB3
5.233%
7/15/2019**
$68,485,853
553214AC1
5.463%
7/15/2026**
$153,250,000
553214AD9
5.523%
7/15/2027**
$29,025,000
553214AE7
5.127%
1/15/2031**
$64,380,000
MP Total $1,293,500,000
Mon Power
Environmental
Funding LLC
Environmental
Bond
Environmental
Bond
Environmental
Bond
Environmental
Bond
Control
Control
Control
Control
Mon Power Environmental Funding LLC Total
$315,140,853
*Mon Power assumed primary liability for this note from AE Supply in connection with the Harrison transfer
** Expected Final Maturity Date
As of March 31, 2015
Published May 1, 2015
FirstEnergy FactBook
78
West Virginia/Maryland – Long-Term Debt Schedules
Type
CUSIP
Interest
Rate
Maturity
Amount
Outstanding
First Mortgage Bond
737662BR6
5.125%
8/15/2015
$145,000,000
First Mortgage Bond
737662BS4
5.8%
10/15/2016
$100,000,000
First Mortgage Bond
Private
Placement
4.44%
11/15/2044
$200,000,000
Company
Potomac
Edison
PE Total
$445,000,000
Environmental Control
Bond
69336NAB5
5.233%
7/15/2019*
$23,071,830
Environmental Control
Bond
69336NAC3
5.463%
7/15/2026*
$50,700,000
69336NAD1
5.523%
7/15/2027*
$9,975,000
69336NAE9
5.127%
1/15/2031*
$21,510,000
Potomac Edison
Environmental Control
Environmental
Bond
Funding LLC
Environmental Control
Bond
Potomac Edison Environmental Funding LLC Total
$105,256,830
* Expected Final Maturity Date
As of March 31, 2015
FirstEnergy FactBook
Published May 1, 2015
79
41
FirstEnergy FactBook
Published May 1, 2015
Creating Value for Investors
Regulated Generation
Published May 1, 2015
FirstEnergy FactBook
80
Regulated Generation – 2013 - 2015 Output
M MWH
Total: 14
Total: 21
Total: 21
2013A
2014A
2015F
25
20
15
10
5
0
Increase in 2013A and 2014A reflects Harrison/Pleasants asset transfer, which occurred in October 2013
FirstEnergy FactBook
Published May 1, 2015
81
42
FirstEnergy FactBook
Published May 1, 2015
Regulated Generation
Fuel
Total Fleet – Coal Sources
Supercritical
Units
Plants
Units
NAPP
Harrison
1-3

Fort Martin
1-2

OFA
Scrubbers1
Western
ILB


Supercritical
Fossil Environmental Controls
NOx Controls
Plant
Particulate
Cooling Towers
SCR
Harrison 1-3
1,984
Fort Martin 1 & 2
1,098
Sub-total
1Scrubbed
SO2 Controls
NDC
SNCR

LNB


Electro/Other2
Lo-S Fuel









3,082
coal units have FGD (Flue Gas Desulfurization - equipment to remove sulfur from flue gas after combustion)
Controls can include Venturi Scrubber or Electrostatic Precipitator
2Particulate
Published May 1, 2015
FirstEnergy FactBook
82
Regulated Generation – Plant Deactivations
■ 660 MW deactivated as of September 1, 2012
Regulated
NDC MW
2012 M
MWH
2012
Capacity
Factor (%)
Deactivation Date
Albright
292
0.2
10
9/1/2012
Rivesville
126
0.0
0
9/1/2012
Willow Island
242
0.0
1
9/1/2012
Total
660
0.2
FirstEnergy FactBook
Published May 1, 2015
83
43
FirstEnergy FactBook
Published May 1, 2015
Regulated Generation – MATS Overview
■ MATS
– Total cost estimate of $192M, of which $87M has been spent
through March 31, 2015
Plant
Technologies
Harrison 1-3
Precip Changes, FGD changes, SCR Catalyst, Duct Repairs,
CEMS
Fort Martin 1 & 2
GORE Mercury Control System, Duct Repairs, CEMS
Published May 1, 2015
FirstEnergy FactBook
84
Regulated Generation – Plant Details
Net
Maximum
Year Plant
Units
Capacity Commissioned
(MW)
State
Utility
Fuel
Type
Bath County Rest of RTO
VA
MP
Hydro
6
487*
1985
Fort Martin
Rest of RTO
WV
MP
Coal
2
1,098
1967
Harrison
Rest of RTO
WV
MP
Coal
3
1,984
1972
MP
Coal
Multiple
11**
Rest of RTO Total
3,580
Plant
OVEC
Yards Creek
PJM Zone
Rest of RTO Multiple
EMAAC
NJ
JCP&L
Hydro
3
210
EMAAC Total
210
Regulated Generation Total
3,790
1965
*Represents MP’s approximate 41% shareholder interest in AGC, which owns a 40% interest in Bath County, a pumped-storage hydroelectric station.
The station is operated by 60% owner Virginia Electric and Power Company
**Represents MP’s 0.49% entitlement based on its participation in OVEC
FirstEnergy FactBook
Published May 1, 2015
85
44
FirstEnergy FactBook
Published May 1, 2015
Creating Value for Investors
Transmission
FirstEnergy FactBook
Published May 1, 2015
86
Transmission – Enhancing Transmission Reliability for Customers
Energizing the Future
■ FirstEnergy’s overall transmission program
■ Includes all investments in ATSI, TrAILCo and other utility operating companies within the
FirstEnergy footprint
2014-2017 Growth Program
■ $4.2B plan initially focused primarily in ATSI and extending east
over time
Benefits
■ Focused on smaller-scale projects with near-term completion dates
– Majority of projects located in the ATSI region, target 69kV lines, and outside of the RTEP
approval process
– Construction to occur on land where most rights-of-way are already secured
Transmission System
Assessment and Future
Outlook Report
2014-2017
■ Enhanced system reliability and customer service
■ Older equipment replaced with updated technology
■ Decreased maintenance costs by converting to condition-based
maintenance program that allows for equipment replacement using
real-time data
■ Local employment opportunities for ~1,100 contractors annually
2018 and Beyond
■ $15B in incremental opportunities for reliability enhancement
FirstEnergy FactBook
Published May 1, 2015
87
45
FirstEnergy FactBook
Published May 1, 2015
Transmission – Energizing the Future
To increase system reliability and capacity for
existing and new customers
■ Upgrade condition / health of the system
■ Increase operating flexibility/margin
Reliability
Enhancements
• Outage scheduling
• System/storm restoration
• Load serving capability for existing and new customers
$1.6B
■ Increase system performance/reliability
• Decrease exposure to outages
• Decrease outage time
■ Increase automation and communication within the system
■ Enhance dynamic performance
■ Reduce future transmission investment costs
■ Preserves the reliability of PJM’s transmission system
■ Formula rate recoverable in both ATSI and TrAILCo
Regulatory
Required
■ RTEP approved projects (PJM requested to support grid reliability)
$2.6B
■ Generator deactivation projects
■ Enables future markets
■ Emerging shale gas projects
$4.2B plan initially focused primarily in ATSI and extending east over time
Published May 1, 2015
FirstEnergy FactBook
88
Transmission – Formula Rate Summary
ATSI
TrAILCo
Jurisdiction
FERC
FERC
Filing Month
November
May
FERC approved
ROE
12.38% ***
12.70% TrAIL the Line & Black Oak SVC
11.70% All other projects
Rate Base
$1.8B*
$1.2B**
Transmission
system locations
OE, PP, CEI, and TE
WPP, MP, and PE. Also some portions of
JCP&L, ME, and PN
Term
January – December
June – Following May
Test Year
Forward-Looking: Projects rate base and
expenses for the calendar year; Network
Service Peak Load updated effective
January 1***
Forward-Looking: Utilizes prior year plant-inservice from FERC Form 1 and adds capital
additions projected to be in service within
current calendar year
True-up
Mechanism
Yes
Yes
Revenue Requirement used to calculate an
Annual Network Rate and Point-to-Point rates
Revenue Requirement by project:
 TrAIL the Line
 Individual RTEP projects
Calculation
* Represents projected rate base from its 2015 Projected Transmission Revenue Requirement effective January 1, 2015, through December 31, 2015.
** Represents projected rate base from its annual update on May 15, 2014 for rates effective June 1, 2014
*** On December 31, 2014, FERC accepted, subject to potential refund, ATSI’s rate filing to amend its formula rate to a forward-looking test year effective
January 1, 2015. FERC also determined the ROE is subject to inquiry and potential refund as part of the settlement and hearing proceedings.
FirstEnergy FactBook
Published May 1, 2015
89
46
FirstEnergy FactBook
Published May 1, 2015
Transmission – Enhancing Transmission Reliability for Customers
Future
■ $4.2B over 2014-2017: Majority of nearterm projects in ATSI
■ Funding Strategy: FET up to 65% Debt,
ATSI & TrAILCo up to 40% Debt
MP, WPP, PE
2017
JCP&L, ME, PN
2014
ATSI and TrAILCo
Transition from ATSI … to
TrAILCo … then east to utility
operating companies over time
FirstEnergy FactBook
Published May 1, 2015
90
Transmission – Enhancing Transmission Reliability for Customers
ATSI 69kV – 138kV System Network
■ Only provides transmission services;
does not provide retail utility
services or own generation assets
■ Wholly owned indirect subsidiary of
FE Corp.
■ Owns, operates and maintains over
~7,400 circuit-miles of transmission
lines, substations and other
transmission facilities operated at
nominal voltages of 345 kV, 138 kV
and 69 kV
Transmission Line
Nominal Voltage
138 kV
69 kV
Substation
CEI
OE
PP
TE
Near-term projects planned within ATSI
FirstEnergy FactBook
Published May 1, 2015
91
47
FirstEnergy FactBook
Published May 1, 2015
Transmission – TrAILCo Footprint
Potter
Cabot
PA
OH
■ Projects target areas within
FE footprint outside of ATSI
Wylie Ridge
Kammer
502 Junction
Pleasureville
Black Oak
NJ
MD
Doubs
N. Shenandoah
■ Assets assigned to TrAILCo
must:
Mt. Storm
Meadow
Brook
– Receive PJM RTEP approval
Loudoun
VA
– Operate at 100kV and above
■ Owns the 150-mile TransAllegheny Interstate Line
(TrAIL)
Beddington
WV
FirstEnergy Utility Service Area
FirstEnergy VA Transmission Zone
TrAIL 500 kV Line
Substation
FE TrAIL 50% Joint Ownership with
Dominion Resources
Dominion Resources Owned
Published May 1, 2015
FirstEnergy FactBook
92
Transmission – Enhancing Transmission Reliability for Customers
Energizing the Future
Capital Program
2014A*
2015F
2016F
2017F
Formula Rate
Recoverable
Projects designed to upgrade and enhance
system conditions, performance, capacity
and reliability. Receive ATSI or TrAILCo
formula rates.
$1,177M
$805M
$810M
$725M
$246M
$165M
$185M
$125M
$1,423M
$970M
$995M
$850M
Baseline
Planned capital projects at operating
companies (JCP&L, ME, MP, PN, PE, and
WPP).
Total
Expected ATSI & TrAILCo average annual earnings growth of 20+%
* Includes $38M associated with the capital component of the Pension/OPEB mark-to-market adjustment
FirstEnergy FactBook
Published May 1, 2015
93
48
FirstEnergy FactBook
Published May 1, 2015
Transmission – Upgrade Condition of the System
■ Replace oil, single-pressure and two-pressure,
gas-insulated circuit breakers with new singlepressure, gas-insulated circuit breakers due to
deteriorating condition. New EHV circuit
breakers will also include on-line diagnostic
systems with capabilities to provide data to the
new Asset Health System
■ Replace power transformers due to
deterioration of internal insulation with new
transformers that include on-line diagnostic
systems with capabilities to provide data to the
new Asset Health System
Oil pressure gas insulated circuit breaker (on left), replaced by gasinsulated circuit breaker (on right)
■ Evaluate and rebuild aging EHV and HV
transmission lines (~2,500 circuit miles of 69kV
and ~5,000 circuit miles of 138kV and 345kV)
■ Based on the initial reliability review, anticipate
rebuilding approximately 50% of the 69kV and
20% of the 138kV lines; however these
percentages may increase as overall condition
assessment of the ATSI transmission system is
completed
New transformers will provide data to the Asset Health
System
FirstEnergy FactBook
Published May 1, 2015
94
Transmission – Enhance System Performance
■ Implement an Asset Health System
– Provide situational awareness through real-time, consolidated data on asset condition
– Reduce maintenance by enabling real-time data event analysis and condition assessment
■ Physical Security Enhancements
– Replace existing chain link perimeter fencing with no cut /no climb product where
necessary
– Expand use of perimeter video,
thermal imaging and virtual
inspection
■ Expand FirstEnergy’s fiber and
core network to critical
transmission facilities
– Reduce/eliminate dependence on
unreliable third-party communication
assets
– Increased capacity enables diagnostic
data to provide proactive monitoring
and enhanced reliability of critical
equipment
FirstEnergy FactBook
Published May 1, 2015
95
49
FirstEnergy FactBook
Published May 1, 2015
Transmission – Add Operating Flexibility and Capacity
■ Rebuild existing single-circuit transmission lines as double-circuit
transmission lines
■ Build line segments to create parallel paths (loop feeds) to existing
substations
■ Reconfigure longer transmission lines with high customer loads to
decrease the number of customers impacted by a single operational event
Current Configuration
All customers are impacted by a single event
Substation A
Substation B
Outage
Enhancements
Two customers are impacted by a single event
New Switching Equipment
Substation A
New Remote-Controlled Sectionalizing Equipment
FirstEnergy FactBook
Substation B
Published May 1, 2015
96
Transmission Program Status
■ Burns & McDonnell hired to support engineering, procurement,
construction and completion of capital portfolio created for
Energizing the Future
– Design engineering continues, with several local Ohio firms supplementing
Burns & McDonnell
– A four-year project list has been established (construction complete or
underway on numerous projects), and coordination of future outages and
construction is in progress
■ Quanta Services augmenting physical labor (linemen and
substation electricians) required to perform reliability-based work
■ Manufacturer production and deliveries to support construction
activities through 2014 and 2015; Equipment includes:
– 750 HV circuit breakers
– 60 HV power transformers
– 25 EHV power transformers
FirstEnergy FactBook
Published May 1, 2015
97
50
FirstEnergy FactBook
Published May 1, 2015
2014 Accomplishments
■ Completed Projects
Energizing the Future
– Approximately:
($ Millions)
– 960 pieces of substation
equipment replaced
1600
– 140 miles of Transmission line
rebuild projects completed
1400
– 70 miles of Transmission line
capacity upgrade projects
completed
1200
1000
– Physical Security Upgrade
projects completed at
approximately 50 Substations
800
600
– One Synchronous Condenser
conversion and three Static Var
Compensators (SVC) projects inservice
400
200
– Provides ~1,900 MVAR of support
– Approximately 70 Communication
Upgrade projects completed
0
Jan Feb Mar Apr May Jun
Spend (Cumulative)
Jul Aug Sep Oct Nov Dec
In Service Dollars (Cumulative)
Published May 1, 2015
FirstEnergy FactBook
98
Transmission Program Status
■ 2015 Projects
– Over 1,000 pieces of substation equipment slated for replacement/upgrades
including:
– 60+ transformers, 17 capacitor banks, 80+ breakers
– Approximately 300 miles of Transmission line projects
– Telecom/IT projects
– 7 SVC Projects
– 1 Synchronous Condenser conversion project in 2015
Energizing the Future 2015
($ Millions)
1200
1000
800
600
400
200
0
Jan
Feb
Mar
Apr
May
Jun
Jul
FirstEnergy FactBook
Aug
Sep
Oct
Nov
Dec
Published May 1, 2015
99
51
FirstEnergy FactBook
Published May 1, 2015
Transmission – Political Landscape
Federal Energy Regulatory Commission (FERC)
Commissioners
Current Term
Norman C. Bay (D)- Chairman
Expires in 2018
Philip D. Moeller (R)
Expires in 2015
Tony Clark (R)
Expires in 2016
Colette D. Honorable (D)
Expires in 2017
Cheryl A. LaFleur (D)
Expires in 2019
FirstEnergy FactBook
Published May 1, 2015
100
Transmission – Long-Term Debt Schedules
Company
FET
CUSIP
Interest
Rate
Maturity
Amount
Outstanding
Senior Note
33767BAB5
4.35%
1/15/2025
$600,000,000
Senior Note
33767BAA7
5.45%
7/15/2044
$400,000,000
Type
FET Total
ATSI
$1,000,000,000
Senior Note
030288AA2
5.25%
1/15/2022
$400,000,000
Senior Note
030288AB0
5.00%
9/1/2044
$400,000,000
ATSI Total
TrAILCo
Senior Note
893045AE4
3.85%
6/1/2025
$800,000,000
$550,000,000
As of March 31, 2015
FirstEnergy FactBook
Published May 1, 2015
101
52
FirstEnergy FactBook
Published May 1, 2015
Creating Value for Investors
Competitive Operations
Published May 1, 2015
FirstEnergy FactBook
102
Taking Our Generation to the Competitive Market
Focus on
Strong
Operations
and Financial
Results
Effectively
Hedge
Generation
Minimize
Overall
Business
Risk
FirstEnergy FactBook
Published May 1, 2015
103
53
FirstEnergy FactBook
Published May 1, 2015
Taking Our Generation to the Competitive Market
Effectively hedge generation
■ Utilize strong
competitive
knowledge
■
■
■ Take advantage of
flexibility given
current committed
position
■
■
Flexibility to continue POLR, Governmental Aggregation, and selected
large commercial-industrial sales
Enables the use of retail margin uplift to hedge during periods of low
wholesale prices
Employ a variety of hedging tools, including existing retail sales
commitments, traditional forward wholesale sales and potentially Utility
PPAs
Strong focus on portfolio optimization and risk management
“Long” generating strategy
Annual generation resources of 80-85M MWH
■ Benefit from established baseline of higher margin Governmental
Aggregation load (13M MWH) and natural attrition of selected channels
through 2019
■ Reserve 10-20M MWH to protect weather-sensitive loads and to take
advantage of opportunities resulting from scarcity pricing
■ Target 10-45M MWH annually through POLR, Governmental Aggregation
and selected large commercial-industrial sales
■ Balance remainder of portfolio for sales in the wholesale market and
potentially Utility PPAs
■ Leverage clean,
efficient generation
portfolio
■ Mitigate risk
■ Maximize margins
Adapt Competitive Operations to changing market dynamics
FirstEnergy FactBook
104
Published May 1, 2015
Existing Committed Sales
■ Retain POLR, GA, and selected large commercial-industrial contracts
■ Exit MCI, MM and certain LCI contracts by natural attrition
Committed Load by Segment with Early Termination
TWh
Q2, 2015F:
 Start to build length in the portfolio  Open position increases at a time when generation is deactivated for MATS
8
6
Q3, 2016:
 Contracts for LCI, MM, and MCI largely expire
4
2
FE OH GA
Other GA
LCI Direct
LCI Agent/MCI/MM
Wholesale
Structured/Muni/PIPP
POLR
12/1/2017
11/1/2017
9/1/2017
10/1/2017
8/1/2017
7/1/2017
6/1/2017
5/1/2017
4/1/2017
3/1/2017
2/1/2017
1/1/2017
12/1/2016
11/1/2016
9/1/2016
10/1/2016
8/1/2016
7/1/2016
6/1/2016
5/1/2016
4/1/2016
3/1/2016
2/1/2016
1/1/2016
12/1/2015
11/1/2015
9/1/2015
10/1/2015
8/1/2015
7/1/2015
6/1/2015
5/1/2015
4/1/2015
0
Supply
Expected significant level of uncommitted sales beginning mid-2015 provides flexibility
As of March 31, 2015
FirstEnergy FactBook
Published May 1, 2015
105
54
FirstEnergy FactBook
Published May 1, 2015
Flexible Hedging Platform to Bring Our Generation to Market
Open Position (M MWH)
TWh
7
6
Potential ESP IV PPA (Sammis,
Davis-Besse, OVEC)
5
4
Generation holdback sold
to spot market
3
2
1
0
PPA
To Be Sold
holdback
Significant level of committed sales through mid-2015
As of March 31, 2015
Published May 1, 2015
FirstEnergy FactBook
106
Optionality and Variety of Hedging Resources
Channel
Description
Value
Sales in forward power markets made to hedge
generation
Provides flexibility in volume and timing of hedge
Buying group formed by communities which choose
electric supplier for all members in the group. Pricing
is fixed or is a percentage discount off the price to
compare, which is determined through utility default
service auctions. Current contracts run through 2019.
Higher margin load, pricing of majority of sales
moves with market, minimal acquisition cost,
minimizes risk of POLR
Tranches of non-shopping load that is won through
utilities’ default service auctions
Higher margin load, minimal acquisition cost and
flexibility of participation
Includes municipality sales, co-operative sales,
bilateral sales, and unique transactions
Higher margin wholesale transactions made for
strategic purposes
LCI
Selected/strategic direct sales to large commercial
and industrial customers
Higher load factors, less weather sensitive, flexibility
of term; a wholesale-type load with better margins
Utility PPA
Dedicated plant output (MW) to distribution utilities
through PPA
Cost-based recovery; provides more revenue
certainty
Spot Market
Sales
Sales in day-ahead or real-time to take advantage of
market volatility/scarcity pricing
Having a reserve dedicated to spot provides
flexibility to manage weather sensitive loads and
take advantage of market volatility
MCI and MM
Sales
No new sales. Small Commercial and Residential
customers. Contracts expire naturally through 2018.
High cost to acquire and support customers; highly
weather sensitive
Wholesale Sales
GA
POLR
Structured
FirstEnergy FactBook
Published May 1, 2015
107
55
FirstEnergy FactBook
Published May 1, 2015
Target Portfolio Mix
Weather
Sensitive
Annual Load
(M MWH)
GA
/
10-15
POLR
0-10
LCI Direct*
0-20
Block Wholesale
10-20
Spot Wholesale
10-20
Annual Generation Resources = 80-85M MWH
*LCI Direct is less weather sensitive than GA and POLR
FirstEnergy FactBook
Published May 1, 2015
108
Re-positioning and De-risking CES’ Sales Portfolio
Mitigating risk by reducing sales to weather sensitive channels
Total Annualized Usage of CES Retail & POLR portfolio
2015 vs. 2014(1)
45%
M MWH
60
Indicative change (in MW) of CES
demand obligation for each +/- 1ºF
change in temperature
53
50
28%
40
30
+/-
2014
2015
Change
Winter
85
70
(18)%
Summer
285
150
(47)%
25%
29
29
24
21
20
18
10
0
Residential
POLR/Structured/
Muni/PIPP
Jan-14
Commercial/
Industrial
(1) Expected annualized usage based on utility data as of January 2014
and March 2015. Customer data does not represent actual or projected
annual load for calendar year 2014 or 2015.
Mar-15
As of March 31, 2015
FirstEnergy FactBook
Published May 1, 2015
109
56
FirstEnergy FactBook
Published May 1, 2015
Repositioning our Competitive Fleet Over Time
MW
19,785 MW
18,000
13,169 MW
80-85M MWH
94M MWH
21,000
(3,884)
Renewables
8%
Gas/Oil
9%
(885)
(1,476)
15,000
12,000
9,000
(527)
Renewables
9%
156
Gas/Oil 12%
Coal
63%
Coal
48%
6,000
3,000
0
Nuclear
31%
Nuclear
20%
2012
2012
Plant
Deactivations in
Plant
RMR Units
Deactivations 2012-2013 April 2015
Deactivations
Harrison /
Hydro Asset
Hydro
Asset
Harrison
/
Pleasants
Sales
Sales
Pleasants
Asset
Asset Transfer
Transfer
Other
Other
Other*
Current
Post
2015
Current generation output of 75-80M MWH; additional resources of 0-5M MWH (includes Wind/Solar/OVEC)
The character and operation of our fleet has changed over the past several years
■ 3,884 MW deactivated 2012-2013
■ 885 MW additional deactivations in April 2015
■ 1,847 MW includes asset transfer and sales and other actions including net uprates (96 MW), additional wind
and solar PPA agreements (120 MW), less deactivation of Mad River plant (60 MW)
In 2015, the competitive generation portfolio will operate similar to a natural gas portfolio in that ~100% of the
power generated will come from low or non-emitting sources yet also offer a diverse platform of resources
FirstEnergy FactBook
110
Published May 1, 2015
2015F CES Adjusted EBITDA
Closed
Open
M MWH
Rate
Total
M MWH
Rate
$M
$M
M MWH
Rate
$M
LCI/MCI/MM
27.6
$56
$1,555
GA & POLR
26.3
$64
$1,675
26.3
Structured & Muni
10.6
$45
$470
10.6
$45
$56
$1,555
$64
$470
Wholesale
5.1
$38
$190
13.7
$35.85
$1,675
$490
Other
3.0
Sales:
8.6
$35.00
$300
3.0
$890
Capacity Revenue – BRA
Total Revenues
27.6
72.6
$890
$4,780
8.6
$35.00
$300
81.2
$5,080
Expenses:
Capacity & Delivery
Expenses
($1,235)
($20)
($1,255)
Purchased Power
9.5
($43)
($405)
9.5
($43)
($405)
Nuclear Fuel
31.0
($7.00)
($215)
31.0
($7.00)
($215)
Fossil Fuel
32.1
($26.65)
($230)
40.7
($26.70)
($1,085)
($250)
81.2
Total Expenses
72.6
Commodity Margin
Commodity Margin
(excl. Capacity Revenue)
($855)
8.6
($2,710)
8.6
($26.90)
$2,070
~$16
$1,180
Closed Contribution
$825-$900
($2,960)
$50
~$6
+
Open Contribution
$50
$2,120
$50
~$15
=
$1,230
CES Adjusted EBITDA1 – 2015F
$875 -$950
Please see slide 113 for additional notes describing “Sales” and “Expenses”
1 Total CES 2015F Adjusted EBITDA, a non-GAAP financial measure, is reconciled to 2015F CES Net Income on slide 142, and is based on market prices as of
March 31, 2015. The “Closed Contribution” to Adjusted EBITDA is based on committed sales whereas the “Open Contribution” to Adjusted EBITDA is based on currently
uncommitted sales that are assumed to be sold in the wholesale market assuming market prices as of March 31, 2015. The purpose of the table above is to summarize
the impact on Adjusted EBITDA of changes in market prices on currently uncommitted sales.
FirstEnergy FactBook
Published May 1, 2015
111
57
FirstEnergy FactBook
Published May 1, 2015
2016F CES Adjusted EBITDA
Closed
Open
M MWH
Rate
$M
LCI/MCI/MM
12.5
$58
GA & POLR
17.0
$64
Structured & Muni
7.8
$44
$340
Wholesale
7.6
$38
$290
Other
2.5
M MWH
Rate
Total
$M
M MWH
Rate
$M
$730
12.5
$58
$730
$1,080
17.0
$64
$1,080
7.8
$44
$340
43.0
$37.35
$1,605
Sales:
35.4
$37.15
$1,315
2.5
$670
Capacity Revenue
Total Revenues
47.4
$670
$3,110
35.4
$37.15
$1,315
82.8
$4,425
Expenses:
Capacity & Delivery
Expenses
($660)
($95)
($755)
Purchased Power
4.9
($45)
($220)
4.9
($45)
($220)
Nuclear Fuel
32.3
($7.15)
($230)
32.3
($7.15)
($230)
10.2
($27.45)
($970)
45.6
($27.45)
($1,250)
($1,065)
82.8
Fossil Fuel
Total Expenses
47.4
Commodity Margin
Commodity Margin
(excl. Capacity Revenue)
($280)
35.4
($1,390)
35.4
($27.45)
$1,720
~$22
$1,050
Closed Contribution
($2,455)
$250
~$7
+
$500-$600
$1,970
$250
Open Contribution
~$16
=
$250
$1,300
CES Adjusted EBITDA1 – 2016F
$750 -$850
Please see slide 114 for additional notes describing “Sales” and “Expenses”
1 Total CES 2016F Adjusted EBITDA, a non-GAAP financial measure, is reconciled to 2016F CES Net Income on slide 142, and is based on market prices as of
March 31, 2015. The “Closed Contribution” to Adjusted EBITDA is based on committed sales whereas the “Open Contribution” to Adjusted EBITDA is based on currently
uncommitted sales that are assumed to be sold in the wholesale market assuming market prices as of March 31, 2015. The purpose of the table above is to summarize
the impact on Adjusted EBITDA of changes in market prices on currently uncommitted sales.
FirstEnergy FactBook
Published May 1, 2015
112
2015 CES Adjusted EBITDA Notes
■ Sales:
– Volume in all channels, with the exception of wholesale, is subject to fluctuations due to weather and customer
behavior.
– Portions of “Closed” GA revenues are not fixed as they are indexed to the utility price-to-compare (PTC).
– When wholesale volumes are committed they are categorized as “Closed” and moved to the appropriate channel.
Additional retail channel sales could include an operating margin of ~$2 to $3 per MWH.
– Wholesale “Open” rate is the weighted average of generation length based on forward market prices at AD Hub as
of March 31, 2015. The “Closed” position represents physical and financial transactions executed to reduce
market price risk.
– “Other” sales include distribution losses and pumping for Hydro units.
■ Expenses:
– Capacity expense is the cost associated with serving load, net of incremental capacity auctions and bilateral
transactions and credits associated with serving load, Capacity Transfer Rights or CTRs.
– Delivery expenses, net of delivery revenues, include congestion, losses, ancillaries, Network Integration
Transmission Service and the cost of Financial Transmission Rights. Can vary based on delivery location,
channel and market conditions.
– A delivery expense of ~$2 – $4/MWH is incurred to serve wholesale load
– A delivery expense of ~$3 – $6/MWH is incurred to serve retail load
– Generation volume is committed in the following order: (1) Purchased Power, which includes Renewables/OVEC
of ~2M MWH and additional Bilateral/Spot Purchases, (2) Nuclear, and (3) Fossil.
– Fossil Fuel expense includes Coal, Gas, and Hydro.
– Nuclear Fuel expense reflects the suspension of the DOE nuclear fuel disposal fee.
– Total CES 2015F Adjusted EBITDA guidance, a non-GAAP financial measure, is reconciled to 2015F CES Net
Income on slide 142, and is based on market prices as of March 31, 2015. The +/- $38 million range is applied to
account for potential variation in generation fleet performance, load fluctuations and other variable/fixed costs.
FirstEnergy FactBook
Published May 1, 2015
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58
FirstEnergy FactBook
Published May 1, 2015
2016 CES Adjusted EBITDA Notes
■ Sales:
– Volume in all channels, with the exception of wholesale, is subject to fluctuations due to weather and customer
behavior.
– Portions of “Closed” GA revenues are not fixed as they are indexed to the utility price-to-compare (PTC).
– When wholesale volumes are committed they are categorized as “Closed” and moved to the appropriate channel.
Additional retail channel sales could include an operating margin of ~$2 to $3 per MWH.
– Wholesale “Open” rate is the weighted average of generation length based on forward market prices at AD Hub as
of March 31, 2015. The “Closed” position represents physical and financial transactions executed to reduce
market price risk.
– “Other” sales include distribution losses and pumping for Hydro units.
– Capacity Revenue includes revenues from the BRA as well as the results of incremental capacity auctions,
bilateral transactions and credits associated with serving load (CTRs).
■ Expenses:
– Capacity expense is the cost associated with serving load.
– Delivery expenses, net of delivery revenues, include congestion, losses, ancillaries, Network Integration
Transmission Service and the cost of Financial Transmission Rights. Can vary based on delivery location,
channel and market conditions.
– A delivery expense of ~$2 – $4/MWH is incurred to serve wholesale load
– A delivery expense of ~$3 – $6/MWH is incurred to serve retail load
– Generation volume is committed in the following order: (1) Purchased Power, which includes Renewables/OVEC
of ~2M MWH and additional Bilateral/Spot Purchases, (2) Nuclear, and (3) Fossil.
– Fossil Fuel expense includes Coal, Gas, and Hydro.
– Nuclear Fuel expense reflects the suspension of the DOE nuclear fuel disposal fee.
– Total CES 2016F Adjusted EBITDA guidance, a non-GAAP financial measure, is reconciled to 2016F CES Net
Income on slide 142, and is based on market prices as of March 31, 2015. The +/- $50 million range is applied to
account for potential variation in generation fleet performance, load fluctuations and other variable/fixed costs.
Published May 1, 2015
FirstEnergy FactBook
114
CES Commodity Margin Current Assumptions
Energy Prices
Fuel Prices
2015*
2016
AD Hub Forwards
(On-peak/Off-peak $/MWH)
$39 / $28
$41 / $30
PJM West Forwards
(On-peak/Off-peak $/MWH)
$43 / $29
$46 / $32
Ind Hub
(On-peak/Off-peak $/MWH)
$37 / $27
$40 / $29
Henry Hub Natural Gas
($/MMBTU)
$2.78
$3.11
Dominion South Natural Gas
($/MMBTU)
$1.74
$2.04
*March-December market forwards
Impact to Commodity
Margin/Adjusted EBITDA
Sensitivities**
2015
2016
+ / - $45M
+ / - $175M
+ / - $1/MMBTU Natural Gas
- / + $11M
- / + $28M
+ / - $5/Ton Eastern Coal
- / + $0M
- / + $11M
+ / - $5/Ton Western Coal
- / + $0M
- / + $2M
+ / - $5/MWH RTC Energy
Prices
Fuel Cost Exposure
As of March 31, 2015
**RTC energy price sensitivities relate to the impact of the change in prices on CES’ open position.
Gas and coal sensitivities relate to the impact of the change in prices on CES’ open gas and coal position.
FirstEnergy FactBook
Published May 1, 2015
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FirstEnergy FactBook
Published May 1, 2015
Committed Sales by Zone
2013A
Calendar Year
Committed Sales
2014A
2015F
2016F
M MWH
$M
$/MWH
M MWH
$M
$/MWH
M MWH
$M
$/MWH
M MWH
$M
$/MWH
ATSI
33
$2,155
$54
33
$1,910
$57
28
$1,650
$59
23
$1,285
$56
Rest of RTO
49
2,450
50
46
2,345
51
31
1,560
50
18
910
51
MAAC
12
755
65
11
730
67
6
420
66
3
180
68
EMAAC
2
160
75
2
175
75
1
95
74
<1
25
77
MISO
6
285
47
7
305
47
4
165
45
1
40
40
109
$5,805
$53
99
$5,465
$55
70
$3,890
$56
45
$2,440
$54
$M
$/MWH
M MWH
$M
$/MWH
M MWH
$M
$/MWH
M MWH
Total Committed
Sales
PY 13/14A
Planning Year
M MWH
PY 14/15F
PY 15/16F
PY 16/17F
$M
$/MWH
ATSI
39
$2,120
$54
30
$1,705
$59
28
$1,665
$59
18
$990
$55
Rest of RTO
49
2,485
50
40
2,085
52
25
1,240
50
13
665
50
MAAC
11
760
67
10
635
65
4
275
68
2
130
67
EMAAC
2
180
75
2
155
74
1
50
74
<1
15
77
MISO
7
305
46
5
250
46
2
110
46
1
30
52
109
$5,850
$54
87
$4,830
$56
60
$3,340
$56
35
$1,830
$52
Committed Sales
Total Committed
Sales
Numbers may not foot due to rounding
Beginning June 2016, FE Ohio GA rate is forecasted based on projected PTC
As of March 31, 2015
116
Published May 1, 2015
FirstEnergy FactBook
Committed Sales by Channel
2014A
Calendar Year
Committed Sales
2015F
2016F
M MWH
$M
$/MWH
M MWH
$M
$/MWH
M MWH
$M
$/MWH
Wholesale
7
4
40
20
16
13
-
$450
225
2,135
1,190
900
565
-
$67
64
53
61
57
44
-
4
2
22
16
10
11
5
$295
120
1,140
1,045
630
470
190
$68
64
53
66
60
45
38
2
1
9
13
4
8
8
$170
70
490
840
240
340
290
$69
63
55
64
64
44
38
Total Committed Sales
99
$5,465
$55
70
$3,890
$56
45
$2,440
$54
MM
MCI
LCI
GA
POLR
Structured
Planning
Year
PY 14/15F
Jun - Dec 14
Committed
M MWH
Sales
$M
PY 15/16F
Jan - May 15
$/MWH M MWH
$M
Jun - Dec 15
$/MWH M MWH
$M
PY 16/17F
Jan - May 16
$/MWH M MWH
$M
Jun - Dec 16
$/MWH M MWH
$M
Jan - May 17
$M
$/MWH
MM
4
$245
$67
2
$145
$68
2
$150
$69
1
$80
$69
1
$90
$/MWH M MWH
$69
<1
$25
$69
MCI
2
125
65
1
60
66
1
60
64
<1
30
63
1
40
62
<1
20
61
LCI
21
1,105
52
10
560
53
12
580
53
4
230
55
5
260
54
2
100
55
GA
59
11
705
65
7
420
62
9
625
70
6
380
66
7
460
62
5
310
POLR
9
505
59
7
405
57
3
225
66
2
155
64
2
85
64
1
60
65
Structured
8
350
45
5
205
43
6
265
46
4
180
45
4
160
42
2
95
42
-
-
-
-
190
38
5
190
39
3
100
38
1
25
38
$2,095 $56
22
$1,245 $55
23
$1,195 $52
12
$635
$54
Wholesale
-
Total
Committed
Sales
54
$3,035 $56
Numbers may not foot due to rounding
32
$1,795 $56
5
38
Beginning June 2016, FE Ohio GA rate is forecasted based on projected PTC
FirstEnergy FactBook
As of March 31, 2015
Published May 1, 2015
117
60
FirstEnergy FactBook
Published May 1, 2015
CES Generation Portfolio
M MWH
Total: 107
Total: 115
M MWH
Total: 104
140
Total: 80-85
Total: 80-85
2015F
2016F
120
120
100
11
80
32
60
15
40
49
10
1
31
31
22
27
100
80
60
40
52
45
20
20
0
0
2012A
Fossil*
2013A
2014A
Purchased
Power**
Nuclear
Deactivated
Incremental fossil generation
based on market conditions
Planned ongoing generation resources of 80- 85M MWH annually
* Fossil includes Coal, Gas, and Hydro (excluding pumping); excludes deactivated units
** Purchased Power includes Renewables/OVEC and additional Bilateral/Spot Purchases
Published May 1, 2015
FirstEnergy FactBook
118
Competitive Fuel Sources
2013A*
2014A*
2015F
2016F
Fossil (M MWH)
52
45
41
46
Nuclear (M MWH)
31
31
31
32
Total
83
76
72
78
95%-100%
80%-85%
Hedged Fossil
Hedged Nuclear
100%
100%
Nuclear $/MWH
$26.69
$7.79
$27.16
$7.45
~$27.00
~$7.00**
~$27.50
~$7.00**
Total Competitive Fleet $/MWH
$19.61
$19. 07
~$19.00
~$19.00
Fossil $/MWH
2015F Total Fleet–Coal Sources
Supercritical
Units
Subcritical
Units
Plants
Units
NAPP
Mansfield
1-3

Western
Pleasants
1-2

Sammis
6-7


Sammis
1-5


Bay Shore
1
Petcoke

*Fossil includes Coal, Gas, and Hydro (excluding pumping); excludes deactivated units
**Adjusted for suspension of the DOE spent nuclear fuel fee
FirstEnergy FactBook
Published May 1, 2015
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61
FirstEnergy FactBook
Published May 1, 2015
Reliability Pricing Model Capacity
Auction Results
RTO
Price Per Megawatt-Day
ATSI
Rest of RTO
MAAC
EMAAC
2011 – 2012
FRR Integration Auction
$108.89
–
–
–
2012 – 2013
FRR Integration Auction
$20.46
–
–
–
2010-2011
BRA
N/A
$174.29
$174.29
$174.29
2011-2012
BRA
N/A
$110.00
$110.00
$110.00
2012-2013
BRA
N/A
$16.46
$133.37
$139.73
2013-2014
BRA
$27.73
$27.73
$226.15
$245.00
2014-2015
BRA
$125.99
$125.99
$136.50
$136.50
2015-2016
BRA
$357.00
$136.00
$167.46
$167.46
2016-2017
BRA
$114.23
$59.37
$119.13
$119.13
2017 - 2018
BRA
$120.00
$120.00
$120.00
$120.00
Published May 1, 2015
FirstEnergy FactBook
120
Future Capacity Auctions
Base Residual
First Incremental
Second Incremental Third Incremental
2016 - 2017
–
–
July 2015
February 2016
2017 - 2018
–
September 2015
July 2016
February 2017
2018 - 2019
TBD
September 2016
July 2017
February 2018
■ First Incremental Auction for 2016-2017 held in September 2014
– 500 MW of FE Competitive Generation cleared at ~$100/MWD
This schedule does not incorporate any potential changes from PJM’s proposed capacity and energy market reforms currently pending before FERC.
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Published May 1, 2015
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PJM Capacity Revenues
BRA Cleared/Current Available MW
ATSI
RTO
MAAC
EMAAC
TOTAL –
CLEARED/AVAILABLE
Total Capacity Revenue ($M)
13/14
14/15
15/16
Cleared
6,830
5,670
85
55
Cleared
5,645
4,720
85
55
Cleared
7,070
5,040
80
55
Cleared
3,845
3,460
80
55
16/17
Available
2,548
350
-
Cleared
4,285
4,515
75
55
17/18
Available
2,634
49
-
12,640
10,505
12,245
7,440
2,898
8,930
2,683
$140
$485
$1,185
$240
$390
PJM BRA Capacity Revenues ($ Millions)
2014
$180
$150
$5
$5
$340
ATSI
RTO
MAAC
EMAAC
Total Cleared Revenue
2015
2016
$645
$235
$5
$5
$890
2017
$480
$145
$5
$5
$635
$175
$145
$5
$5
$330
■ The “Cleared” MW and Revenues above reflect only results from the PJM Base Residual Auction
■ Units that have been deactivated are included for years in which they cleared as their capacity obligations will be met with
sources that did not clear or with purchased replacement capacity
■ Units that have been sold/transferred are excluded from MW and capacity revenues
■ PY 14/15 includes:
– MW and revenues from the portion of Pleasants transferred to CES
– RMR unit revenues
■ “Available” MW:
– Include MW that did not clear the BRA or incremental auctions and can be offered into future incremental auctions
– If “Available,” MW cleared at $50/MWD in incremental auctions, would produce additional ~$50M in revenues for PY 16/17, ~$45M in
revenues for PY 17/18
Published May 1, 2015
FirstEnergy FactBook
122
Power Price Trends
AD Hub
$/MWH
On Peak
$/MWH
120
110
100
90
80
70
60
50
40
30
20
Off Peak
60
55
50
45
40
35
30
25
20
Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
$/MWH
2012 Actual
90
2013 Actual
80
2014 Actual
70
Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Around the Clock
60
2015 Actuals
50
2015 Forwards
40
Note: As of March 31, 2015
30
20
Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
FirstEnergy FactBook
Published May 1, 2015
123
63
FirstEnergy FactBook
Published May 1, 2015
Commodity Operations – Basis Risk
$/MWH
DTE
2015*
2014
MICHFE
Comed
PPL
PSEG
FE
Hub
PECO
ILL
Hub
PJM
West
Hub
DQE
$8.09
$3.15
JCPL
Meted
Duke
Ohio
($11.19)
AD
Hub
AEP
($3.74)
APS
$0.50
$1.39
Penelec
If Locational Marginal Price at source > LMP at
sink, then basis is negative
■ Basis risk mitigated by limiting geographic scope of sales obligation
■ Basis risk hedged with basis and financial swaps as well as power transactions at the zones
■ Values shown are around-the-clock, day-ahead average basis values
* As of March 31, 2015
Published May 1, 2015
FirstEnergy FactBook
124
Commodity Operations – Annual Historical Basis Values
A negative value means the Locational Marginal Price (LMP)* at the source is greater than the LMP at the sink
Source
Sink
2013
2014
2015*
($/MWH)
($/MWH)
($/MWH)
FE Hub
Ill Hub
(5.96)
(9.34)
(12.53)
FE Hub
Comed
(4.15)
(6.18)
(6.91)
FE Hub
DTE
(3.30)
(1.44)
(7.13)
FE Hub
MichFE
(0.78)
0.40
(2.24)
FE Hub
PJM West Hub
1.88
4.65
9.81
FE Hub
DQE
(1.73)
(3.90)
(5.11)
FE Hub
AD Hub
(1.53)
(2.28)
(2.81)
FE Hub
AEP
(5.21)
(6.36)
(8.36)
FE Hub
Duke Ohio
(2.40)
APS
APS
AD Hub
DQE
(1.73)
(1.93)
(3.00)
(3.74)
(3.16)
(11.19)
(5.36)
(13.49)
APS
PJM West Hub
1.68
3.19
1.43
APS
Penelec
1.40
1.39
0.50
PJM West Hub
PPL
(0.41)
1.12
6.33
PJM West Hub
PSEG
3.52
5.94
11.88
PJM West Hub
PECO
(0.32)
1.57
6.97
PJM West Hub
JCP&L
1.39
3.15
8.09
PJM West Hub
Met-Ed
(0.14)
1.05
5.55
PJM West Hub
Penelec
(0.28)
(1.80)
(0.93)
*Values shown are around-the-clock, day-ahead average basis values
FirstEnergy FactBook
* As of March 31, 2015
Published May 1, 2015
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FirstEnergy FactBook
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Repositioning Our Competitive Generation Portfolio
2012 - 2015
Deactivations
Competitive
NDC MW
2012 M
MWH
2012
Capacity
Factor (%)
Deactivation Date
9/1/2012 (4-5); 4/15/2015 (1-3)
Eastlake 1-5
1,233
4.5
53
Bay Shore 2-4
495
0.4
12
9/1/2012
Armstrong
356
0.3
16
9/1/2012
Lake Shore 18
245
0.2
9
4/15/2015
Ashtabula 5
244
0.2
12
4/15/2015
R. Paul Smith 3-4
116
0.1
12
9/1/2012
Hatfield 1-3
1,710
9.7
64
10/9/2013
47
10/9/2013
Mitchell 2-3
370
1.2
Total
4,769
16.6
Transfers and Sales
Competitive
NDC MW
Date
Harrison / Pleasants Asset Transfer
1,476
10/9/2013
Hydro Asset Sales
527
2/12/2014
Total
2,003
FirstEnergy FactBook
Published May 1, 2015
126
Competitive Generation – Plant Details
Plant Name
PJM Zone
State
Fuel Type Units
Net Maximum
Year Plant
Capacity
Commissioned
(MW)
Bay Shore
ATSI
OH
Coal, Oil
2
153
1955
Davis-Besse
ATSI
OH
Nuclear
1
908
1977
Eastlake
ATSI
OH
Oil
1
29
1972
Mansfield
ATSI
PA
Coal
3
2,490
1976
Perry
ATSI
OH
Nuclear
1
1,268
1987
R.E. Burger
ATSI
OH
Oil
1
7
1972
Sammis
ATSI
OH
Coal, Oil
8
2,223
1959
OH
Natural Gas,
Oil
2
545
1973
West Lorain
ATSI
Total ATSI Zone Generation
Forked River*
EMAAC
NJ
Natural
Gas
Total EMAAC Zone Generation
7,623
86
86
*Long-term PPA
FirstEnergy FactBook
Published May 1, 2015
127
65
FirstEnergy FactBook
Published May 1, 2015
Competitive Generation – Plant Details (Continued)
Plant Name
PJM Zone
State
Fuel Type
Units
Net Maximum
Year Plant
Capacity (MW) Commissioned
Hunlock
MAAC
PA
Natural Gas
Wind Farms*
MAAC
Multiple
Wind
1
45
Bath County
Rest of RTO
VA
Hydro
6
713**
1985
Beaver Valley
Rest of RTO
PA
Nuclear
2
1,872
1976
Buchanan
Rest of RTO
VA
Natural Gas
1
43
2002
Chambersburg
Rest of RTO
PA
Natural Gas
1
88
2001
Gans
Rest of RTO
PA
Natural Gas
1
88
2000
Maryland Solar* Rest of RTO
MD
Solar
Multiple
20
Coal
Multiple
177***
2
Multiple
2000
277
Total MAAC Zone Generation
322
OVEC*
Rest of RTO
Multiple
Pleasants
Rest of RTO
WV
1,300
1979
Springdale
Rest of RTO
PA
Natural Gas
5
638
1999
Wind Farms*
Rest of RTO
Multiple
Wind
Multiple
199
Coal
Total Rest of RTO Generation
5,138
Total Competitive Generation
13,169
*Long-term PPA
** Represents AES entitlement
***Represents FES’ 4.85% and AE Supply’s 3.01% entitlement
128
Published May 1, 2015
FirstEnergy FactBook
Fossil Environmental Controls
SO2 Controls
NOx Controls
Plant
Supercritical
SCR
Mansfield 1-3
2,490

Pleasants 1-2
1,300

1,200

Sammis 6 & 7
Sub-total
Subcritical
Particulate
NDC
SNCR
COS

LNB
OFA



Scrubbers1
Electro/Other2
Cooling
Towers












4,990
Sammis 1 - 4
720





Sammis 5
290





Bay Shore 1 (CFB 3)
136
Sub-total
Baghouse
3
3



1,156
1Scrubbed
coal units have Flue Gas Desulfurization (FGD – equipment to remove sulfur from flue gas after combustion)
2Particulate Controls can include Venturi Scrubber or Electrostatic Precipitator
3Circulating Fluidized Bed (CFB) Boiler is inherently low emitting for NOx and SO
2
In 2015, nearly 100% of the power the competitive portfolio generates is expected to come from
low- or non-emitting sources, including nuclear, natural gas, scrubbed coal and renewable energy
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Published May 1, 2015
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FirstEnergy FactBook
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Coal Combustion Residuals Impoundments
■ FE operates coal combustion residuals (CCR) impoundments and wastewater
ponds in accordance with federal, state, and local regulatory requirements
– Requirements address design, construction, material placement, structural inspections,
environmental monitoring, and final closure of facilities
■ Majority of FE CCRs are handled as dry material
– Typically sites consist of geotextile liners and or clay soil
– Leachate and/or runoff is collected and treated
– Wet CCR impoundments exist at Pleasants and Mansfield - Little Blue Run (LBR)
■ FE periodically removes CCR material from active wastewater ponds for placement
in dry landfills
– All inactive CCR wastewater treatment ponds at retired plants have been stabilized and will be
closed in accordance with state regulation
■ Closure permit issued by PA Department of Environmental Protection for LBR
– Site will stop receiving CCRs on December 31, 2016, and complete closure over a 12-year-period
– A 30-year period of post closure monitoring will follow
– Bonded closure cost is ~$170M
■ Pleasants impoundment is estimated to reach full capacity no sooner than 2021
– Closure plan to be developed and submitted to WV Department of Environmental Protection 1-2
years prior to closure
FirstEnergy FactBook
Published May 1, 2015
130
MATS Overview
■ MATS
– Total cost estimate of $178M, of which $58M has been spent
through March 31, 2015.
Plant
Technologies
Bay Shore 1*
Baghouse Fabric Filter changes, Mini ACI system, CEMS
Sammis 1-7*
Precip Controls, CEMS
Mansfield 1-3 WFGD Changes, SCR Changes, CEMS
Pleasants 1-2 Precip Changes, FGD Changes, SCR Catalyst, Duct Repairs, CEMS
*Nearly all spending for Bay Shore and Sammis has been completed through 2014.
FirstEnergy FactBook
Published May 1, 2015
131
67
FirstEnergy FactBook
Published May 1, 2015
Nuclear Key Events
Key Events
License
Expiration
Beaver Valley 1
Beaver Valley 2
Davis-Besse
Perry
(939 MW)
(933 MW)
(908 MW)
(1,268 MW)
2036
2047
2017*
2026**
Completed planned
outage
■
■
Implement dry fuel
storage
■
Planned outage
– Refueling
■
2013
Completed fuel pool
rerack
■
Relicensing process
– NRC issued final Safety
Evaluation Report (SER) in
license renewal process
■
■
Planned outage
– Refueling
■
Completed planned outage
– Refueling
– Steam generator
replacement
■
Prepare for License
Renewal Application
submittal
■
Planned outage
– Refueling
■
Relicensing process
– NRC scheduled to issue final
Supplemental Environmental
Impact Statement (SEIS)
■
Submit License Renewal
Application
Planned outage
– Refueling
2014
2015
2016
■
Planned outage
– Refueling
2017
■
Planned outage
– Refueling
*License Renewal Application submitted in 2010
■
Planned outage
– Refueling
■
Implement dry fuel storage
■
■
■
Completed planned outage
Supplemental NRC
inspection (95002)
completed satisfactorily
Planned outage
– Refueling
**Submit License Renewal Application in 2015
132
Published May 1, 2015
FirstEnergy FactBook
Nuclear Operating Costs
Total Production Cost
$/MWH
28
26
24
22
2010
2011
2012
FENOC
2010
O&M ($/MWH)
Fuel ($/MWH)
Generation (M MWH)
2013
2016F
$17
$18
$20
$19
$7
$7
$7
$7
31.0
31.0
32.3
31.8
FirstEnergy FactBook
2013
2016F
2015F
29.8
2012
2015F
2014
30.9
2011
2014
30.9
Published May 1, 2015
133
68
FirstEnergy FactBook
Published May 1, 2015
Beaver Valley
Capital
Expenditures
($ Millions)
250
Major Projects
Baseline
200
150
100
50
0
2010
2011
2012
2013
2014
Major projects include:
– Steam Generator Replacement
– Low-Pressure Turbine Rotor Replacement
– Reactor Vessel Head Replacement
Published May 1, 2015
FirstEnergy FactBook
134
Davis-Besse
Capital
Expenditures
($ Millions)
300
Major Projects
250
Baseline
200
150
100
50
0
2010
2011
2012
2013
2014
Major projects include:
– Reactor Vessel Head Replacement
– Main Generator Rewind
– Steam Generator Replacement
– Alloy 600 Mitigation
FirstEnergy FactBook
Published May 1, 2015
135
69
FirstEnergy FactBook
Published May 1, 2015
Perry
Capital
Expenditures
($ Millions)
120
Major Projects
Baseline
100
80
60
40
20
0
2010
2011
2012
2013
2014
-20
Major projects include:
– Low-Pressure Turbine Rotor Replacement
– Main Generator Rewind
– Alternate Decay Heat Removal System Replacement
Published May 1, 2015
FirstEnergy FactBook
136
Nuclear Fleet Capital
Capital
Expenditures
($ Millions)
600
BV2 Steam Generator/Vessel Head
DB Steam Generator
Base Capital
500
400
300
200
100
0
2014A*
2015F
2016F
2017F
*Includes $8M associated with the capital component of the Pension/OPEB mark-to-market adjustment
FirstEnergy FactBook
Published May 1, 2015
137
70
FirstEnergy FactBook
Published May 1, 2015
Fossil Operating Costs
Total Production Cost
$/MWH
35
33
30
2012
Fossil
2013
2014
2015F
2016F
2012*
2013*
2014*
2015F*
O&M ($/MWH)
$6
$6
$7
$7
2016F
$7
Fuel ($/MWH)
$26
$28
$28
$27
$27
Generation (M MWH)
64.7
61.1
45.4
40.7
45.6
* Includes deactivated units
Published May 1, 2015
FirstEnergy FactBook
138
Fossil Fleet Capital
Capital
Expenditures
($ Millions)
$800
$700
Environmental
Fremont*
Base Capital
$600
$500
$400
$300
$200
$100
$0
2010
2011
2012
2013
*Fremont was sold in July 2011
.
FirstEnergy FactBook
Published May 1, 2015
139
71
FirstEnergy FactBook
Published May 1, 2015
Fossil Fleet Capital
Capital
Expenditures
($ Millions)
$350
Mansfield Dewatering Facility*
MATS
Base Capital
$300
*
$250
*
*
$200
*
$150
$100
$50
$0
2014A**
2015F
2016F
2017F
*Final spending to be determined. Due to closure of LBR by end of December 2016, Mansfield’s CCBs must be converted to a dry product for disposal.
**Includes $11M associated with the capital component of the Pension/OPEB mark-to-market adjustment
FirstEnergy FactBook
Published May 1, 2015
140
Illustration of POLR Components
January 2015 FE Ohio POLR Auction Results
$/MWH
$69.18/MWH*
70
$6.80/MWh
$3.53/MWh
60
50
$23.74/MWh
40
30
20
$35.11/MWh
10
0
12-month tranche
The following components are estimated and for illustrative purposes only:
Energy:
Energy price at AD Hub for FE Ohio slice of system load shape
Capacity:
RPM Capacity expense for product
Delivery:
Contains all non-energy; non-capacity RTO expenses. In OH, Network Integration Transmission Service is excluded.
Risk Premium: Contains margin and risk premiums associated with load shape and price volatility
*Represents the actual OH POLR Clearing Price
FirstEnergy FactBook
Published May 1, 2015
141
72
FirstEnergy FactBook
Published May 1, 2015
Competitive Operations
Net Income (Loss) to Adjusted EBITDA* Reconciliation
($ Millions)
Net Income (Loss) – GAAP
2014A
2015F
2016F
$(337)
$120 – $160
$35 – $145
Special Items (after tax)*
436
70
40 – 30
Operating Earnings
$99
$190- $230
$75 - $175
Income Taxes**
47
100 – 145
45 – 100
Interest Expense, Net
152
160 – 155
165 – 150
Depreciation
387
410 – 405
430 – 415
Amortization***
66
65
70 – 65
Investment Income
(98)
(50)
(35) – (55)
Adjusted EBITDA*
$653
$875– $950
$750 – $850
* Adjusted EBITDA represents GAAP net income adjusted for the special items listed on slide 143 and the addition of Income Taxes; Interest Expense, net;
Depreciation, Amortization and Investment Income.
** Includes income taxes on continued operations and discontinued operations.
*** Amortization expense included in Other Operating Expenses on the Consolidated Statements of Income. Primarily relates to amortization of customer contract
intangible assets, as disclosed in Note 7 - Intangible Assets, and deferred costs on sale leaseback transaction, net, as disclosed in the Consolidated Statements of
Cash Flows. Does not include nuclear fuel amortization of approximately $220M, $215M and $230M, in 2014, 2015, and 2016, respectively.
Published May 1, 2015
FirstEnergy FactBook
142
Competitive Operations – Special Items
($ Millions)
2014A
2015F
2016F
Trust Securities Impairment
$33
$6
$–
Merger Accounting – Commodity Contracts
42
40 – 45
40 – 45
(122)
15
10 – 20
206
11
–
Loss on Debt Redemptions
8
–
–
Regulatory Charges
4
1
–
Pension/OPEB actuarial assumption
327
–
–
Other
74
2
–
70
30
–
$642
$105 – $110
$50 - $65
(206)
(35) – (40)
(20) – (25)
$436
$70
$30 – $40
Pre-tax items
Non-Core Asset Sales/Impairments
Plant Closing Costs
Mark to Market Adjustments
Retail Repositioning Charges
Subtotal
Income Taxes
As of July 25, 2014
After Tax Effect – Special Items
FirstEnergy FactBook
Published May 1, 2015
143
73
FirstEnergy FactBook
Published May 1, 2015
Competitive Operations – Long-Term Debt Schedules
Company
FEGENCO
Type
CUSIP
Interest
Rate
Maturity
Amount
Outstanding
Pollution Control Note
677660UC4
Variable*
10/1/2018
$2,805,000
Pollution Control Note
677525UZ8
Variable*
10/1/2018
$2,985,000
Pollution Control Note
074876HE6
Variable*
10/1/2047
$46,300,000
Pollution Control Note
708686DX5
Variable*
6/1/2028
$15,000,000
Pollution Control Note
074876HK2
Variable*
6/1/2028
$25,000,000
Pollution Control Note
677525VK0
3.75%**
12/1/2023
$234,520,000
Pollution Control Note
708686DA5
3.375%**
12/1/2040
$43,000,000
Pollution Control Note
677660UE0
2.25%**
8/1/2029
$6,450,000
Pollution Control Note
677525VB0
2.25%**
8/1/2029
$100,000,000
Pollution Control Note
074876HF3
2.15%**
3/1/2017
$28,525,000
Pollution Control Note
074876HJ5
2.5%**
12/1/2041
$129,610,000
Pollution Control Note
677525TF4
5.625%
6/1/2018
$141,260,000
Pollution Control Note
708686DB3
2.55%**
11/1/2041
$26,000,000
* Subject to mandatory redemption upon expiration of associated letter of credit; may later be remarketed, subject to market and other conditions
** Currently a fixed rate subject to mandatory put prior to maturity; may later be remarketed, subject to market and other conditions
Note: FES’ debt obligations are guaranteed by its subsidiaries, FEGENCO and FENUGENCO, and FES guarantees the debt obligations of
FEGENCO and FENUGENCO
As of March 31, 2015
Published May 1, 2015
FirstEnergy FactBook
144
Competitive Operations – Long-Term Debt Schedules
Company
FEGENCO
Type
CUSIP
Pollution Control Note
074876HL0
Interest
Rate
Maturity
Amount
Outstanding
3.5%**
4/1/2041
$56,600,000
$177,000,000
Pollution Control Note
677525TK3
5.7%
8/1/2020
Pollution Control Note
677525VP9
3.1%**
3/1/2023
$50,000,000
Pollution Control Note
677660UL4
3.0%
5/15/2019
$90,140,000
Pollution Control Note
677525VR5
3.625%**
10/1/2033
$9,100,000
Pollution Control Note
677660UM2
3.625%**
10/1/2033
$20,450,000
Pollution Control Note
677660UN0
3.95%**
11/1/2032
$33,000,000
Pollution Control Note
677525VS3
3.95%**
11/1/2032
$23,000,000
FEGENCO Total
FENUGENCO
$1,175,195,000
Pollution Control Note
677660UJ9
4.0%**
12/1/2033
$135,550,000
Pollution Control Note
677660UK6
4.0%**
6/1/2033
$46,500,000
Pollution Control Note
677525TY3
3.375%**
7/1/2033
$8,000,000
** Currently a fixed rate subject to mandatory put prior to maturity; may later be remarketed, subject to market and other conditions
Note: FES’ debt obligations are guaranteed by its subsidiaries, FEGENCO and FENUGENCO, and FES guarantees the debt obligations of
FEGENCO and FENUGENCO
As of March 31, 2015
FirstEnergy FactBook
Published May 1, 2015
145
74
FirstEnergy FactBook
Published May 1, 2015
Competitive Operations – Long-Term Debt Schedules
Type
CUSIP
Interest
Rate
Maturity
Amount
Outstanding
Pollution Control Note
677660TV4
3.375%**
7/1/2033
$99,100,000
Pollution Control Note
677525TZ0
3.375%**
1/1/2034
$7,200,000
Pollution Control Note
677660TU6
3.375%**
1/1/2034
$82,800,000
Pollution Control Note
074876GX5
3.375%**
1/1/2035
$72,650,000
Pollution Control Note
677660TP7
5.875%**
6/1/2033
$107,500,000
FENUGENCO Pollution Control Note
677525TE7
5.75%**
6/1/2033
$62,500,000
Pollution Control Note
677660UF7
2.2%**
6/1/2033
$54,600,000
Pollution Control Note
677525VQ7
3.625%**
12/1/2033
$15,500,000
Pollution Control Note
074876HG1
2.2%**
1/1/2035
$60,000,000
Pollution Control Note
074876HH9
2.7%**
4/1/2035
$98,900,000
Pollution Control Note
074876HM8
3.5%**
12/1/2035
$163,965,000
Company
** Currently a fixed rate subject to mandatory put prior to maturity; may later be remarketed, subject to market and other conditions
Note: FES’ debt obligations are guaranteed by its subsidiaries, FEGENCO and FENUGENCO, and FES guarantees the debt obligations of
FEGENCO and FENUGENCO
As of March 31, 2015
Published May 1, 2015
FirstEnergy FactBook
146
Competitive Operations – Long-Term Debt Schedules
Company
FENUGENCO
Interest
Rate
Maturity
Amount
Outstanding
N/A
9.12%
5/30/2016
$14,140,000
Collateralized Lease Bonds
N/A
8.83%
5/30/2016
$6,500,000
Collateralized Lease Bonds
N/A
9.0%
6/1/2017
$17,054,000
Collateralized Lease Bonds
N/A
12.0%
6/1/2017
$425,604
Collateralized Lease Bonds
N/A
8.89%
6/1/2017
$60,048,000
Collateralized Lease Bonds
N/A
8.68%
6/1/2017
$8,668,000
Type
CUSIP
Collateralized Lease Bonds
FENUGENCO Total $1,207,150,604
As of March 31, 2015
FirstEnergy FactBook
Published May 1, 2015
147
75
FirstEnergy FactBook
Published May 1, 2015
Competitive Operations – Long-Term Debt Schedules
Company
FES
CUSIP
Interest
Rate
Maturity
Amount
Outstanding
Senior Note
33766JAD5
6.05%
8/15/2021
$332,305,000
Senior Note
33766JAF0
6.8%
8/15/2039
$363,281,000
Type
FES Total
AE Supply
AGC
$695,586,000
Pollution Control Note
41524CAU8
5.5%
10/15/2037
$73,500,000*
Pollution Control Note
728896CF6
5.25%
10/15/2037
$142,000,000
Senior Note
017363AK8
5.75%
10/15/2019
$155,532,000
Senior Note
017363AM4
6.75%
10/15/2039
$150,034,000
AE Supply Total
$521,066,000
Senior Note
Private
Placement
5.06%
7/15/2021
$100,000,000
AGC Total
$100,000,000
*Mon Power assumed primary liability for this Note in connection with the Harrison transfer
Note: FES’ debt obligations are guaranteed by its subsidiaries, FEGENCO and FENUGENCO, and FES guarantees the debt obligations of
FEGENCO and FENUGENCO
As of March 31, 2015
FirstEnergy FactBook
Published May 1, 2015
148
76
FirstEnergy FactBook
Published May 1, 2015
Creating Value for Investors
Financial
Published May 1, 2015
FirstEnergy FactBook
149
Financial – Liquidity
Available Liquidity
($ Millions)
Revolving Credit Facility
CES
FET
$ 1,500
$ 1,000
Short-term borrowings
(275)
Letters of Credit (LOC)
(48)
Total Utilization
Available External Credit
Capacity
$
(323)
$ 1,177
Cash & Investments
–
Available Liquidity
$ 1,177
FEU
(50)
$ 3,500
(350)
–
FE
Consolidated
FE Corp.
–
$ 6,000
(1,875)
(2,550)
(6)
(54)
$
(50)
$ (2,231)
$ (2,604)
$
950
$1,269
$ 3,396
47
$
997
–
$1,270
1
48
$ 3,444
As of March 31, 2015
FirstEnergy FactBook
Published May 1, 2015
150
77
FirstEnergy FactBook
Published May 1, 2015
Financial – Parental Guarantees
FirstEnergy Corp. Parent
Competitive
Regulated
Corp/Other
$M
Expiration
$M
Expiration
$M
Expiration
Energy Related Contracts
$46
2020-2030
–
–
–
–
Fuel Related Contracts
$31
2021-2031
–
–
–
–
$7
2017
–
–
–
–
$136
–
$174
–
$215
–
$5
2015
$4
2030
$3
–
Retail Contracts
Benefit Related Programs
Other
Total FE Guarantee on
behalf of subsidiaries
$225
$178
$218
As of March 31, 2015
Published May 1, 2015
FirstEnergy FactBook
151
Financial –
Collateral Dependent on Investment Grade Rating
($ Millions)
Collateral Provisions
As of March 31, 2015
Split Rating
(One Rating Agency below investment grade)
Non-Investment Grade Ratings
(All Rating Agencies at or below BB+/Ba1)
Total Exposure from Contractual
Obligations
FES*
FES*
(tied to FE
Corp. rating)
(tied to FES
rating)
Utilities
Total
$53**
$380
$43
$476
$59
$412
$43
$514
$174
$459
$78
$711
*Includes AE Supply
**Exists due to FE Corp’s current Unsecured Rating of BB+ by Standard & Poors
FirstEnergy FactBook
Published May 1, 2015
152
78
FirstEnergy FactBook
Published May 1, 2015
Consolidated Long-Term Debt Maturities
FE Corp.
FES / AE Supply
FET
FEGENCO / FENUGENCO
FEU
($ Millions)
2,000
1,600
1,200
800
400
0
Weighted
2015
2017
2019
2021
2023
2025
Avg. Interest
Rate of Maturing 4.92 4.44 5.90 4.54 4.23 4.79 5.82 5.07 4.05 4.70 4.10
Debt (%)
2027
2029
2031
2033
2035
7.38
2037
2039
2041
2043
6.44 5.93 7.25 6.79
5.40 5.07
Excludes variable rate tax-exempt debt and securitization bonds
As of March 31, 2015
153
Published May 1, 2015
FirstEnergy FactBook
Outstanding Debt by Legal Entity
Hold Co.
At 3/31/2015
Short-term Debt
Long-term Debt
Securitization Bonds
Debt Subtotal
Discounts/Premiums
Purchase Accounting
Capital Leases
Total Balance Sheet Debt
FE
Hold Co.
1,875
4,200
6,075
20
6,095
Metropolitan
Edison
Pennsylvania
Electric
Short-term Debt
Long-term Debt
Securitization Bonds
Debt Subtotal
650
140
790
131
1,330
192
1,654
85
350
42
477
43
105
148
89
850
939
1,125
1,125
289
2,000
159
2,449
30
1,294
315
1,639
34
445
105
584
179
520
699
Discounts/Premiums
Purchase Accounting
Capital Leases
Total Balance Sheet Debt
(9)
24
805
(2)
20
1,671
(1)
11
487
4
152
(1)
19
957
(2)
29
1,152
(7)
2,442
(1)
21
8
1,666
9
7
600
16
12
727
Utilities
At 3/31/2015
Transmission
At 3/31/2015
Ohio
Edison
Cleveland
Electric
FET
Hold Co.
Toledo
Edison
52
1,000
1,052
800
800
550
550
Discounts/Premiums
Purchase Accounting
Capital Leases
Total Balance Sheet Debt
(2)
1,050
(4)
796
(0)
550
FES
Hold Co.
Jersey
Central
Mon
Power
Potomac
Edison
West
Penn Power
TrAIL
ATSI
Short-term Debt
Long-term Debt
Securitization Bonds
Debt Subtotal
Generation
At 3/31/2015
Penn
Power
FE
Generation
FE Nuclear
Generation
Allegheny
Energy
Supply
Allegheny
Generating
Short-term Debt
Long-term Debt
Securitization Bonds
Debt Subtotal
275
696
971
1,177
1,177
1,207
1,207
521
521
4
100
104
Discounts/Premiums
Purchase Accounting
Capital Leases
Total Balance Sheet Debt
(1)
970
16
1,193
1,207
(29)
0
492
104
FirstEnergy FactBook
As of March 31, 2015
Published May 1, 2015
154
79
FirstEnergy FactBook
Published May 1, 2015
Financial – Debt Targets
FirstEnergy
Utilities
(FEU)
Segment
Target Adjusted Debt Ratios*
55%
FirstEnergy
Transmission
(FET)
HoldCo
OpCo
Competitive
Energy
Services
(CES)
65%
40%
<40%
FEU = OE, PP, CEI, TE, JCP&L, ME, PN, MP, PE, WPP
FET = FET, ATSI, TrAILCo
CES = FES, AE Supply
Outstanding debt at FE Corp is not reflected above
*Calculated per rating agency view shown on slide 177
As of March 31, 2015
Published May 1, 2015
FirstEnergy FactBook
155
Financial – FirstEnergy Corp. Long-Term Debt Schedules
Company
FirstEnergy
Corp.
CUSIP
Interest
Rate
Maturity
Amount
Outstanding
Term Loan
N/A
Variable
12/31/2016
$200,000,000
Term Loan
N/A
Variable
3/31/2019
$1,000,000,000
Unsecured Notes
337932AE7
2.75%
3/15/2018
$650,000,000
Unsecured Notes
337932AF4
4.25%
3/15/2023
$850,000,000
Unsecured Notes
337932AC1
7.375%
11/15/2031
$1,500,000,000
Type
FirstEnergy Corp. Total
$4,200,000,000
As of March 31, 2015
FirstEnergy FactBook
Published May 1, 2015
156
80
FirstEnergy FactBook
Published May 1, 2015
Financial – Credit Ratings
Corporate Credit Rating (S&P)
/ Issuer Rating (Moody's) /
Issuer Default (Fitch)
FirstEnergy Corp.
S&P
BBB-
Moodys
Baa3
Fitch
BB+
Senior Secured
S&P
-
Moodys
-
Senior Unsecured
Fitch
-
S&P
BB+
Moodys
Baa3
Fitch
BB+
Outlook
S&P
stable
Moodys
stable
Fitch
stable
FirstEnergy Solutions
BBB-
Baa3
-
-
-
-
BBB-
Baa3
-
stable
stable
-
Allegheny Energy Supply
BBB-
Baa3
-
-
-
-
BBB-
Baa3
-
stable
stable
-
Allegheny Generating Co.
BBB-
Baa3
-
-
-
-
BBB-
Baa3
-
stable
stable
American Transmission Systems Inc.
BBB-
Baa2
-
-
-
-
BBB-
Baa2
-
stable
stable
-
Cleveland Electric Illuminating
BBB-
Baa3
-
BBB+
Baa1
-
BBB-
Baa3
-
stable
stable
-
FirstEnergy Transmission
BBB-
Baa3
-
-
-
-
BB+
Baa3
-
stable
stable
-
Jersey Central Power & Light
BBB-
Baa2
-
-
-
-
BBB-
Baa2
-
stable
stable
-
Metropolitan Edison
BBB-
Baa1
-
-
-
-
BBB-
Baa1
-
stable
stable
-
Monongahela Power
BBB-
Baa2
-
BBB+
A3
-
-
-
-
stable
stable
-
Ohio Edison Co.
BBB-
Baa1
-
BBB+
A2
-
BBB-
Baa1
-
stable
stable
-
Pennsylvania Electric Co.
BBB-
Baa2
-
-
-
-
BBB-
Baa2
-
stable
stable
-
Pennsylvania Power Co.
BBB-
Baa1
-
BBB+
A2
-
-
-
-
stable
stable
-
Potomac Edison Co.
BBB-
Baa2
-
BBB+
A3
-
-
-
-
stable
stable
-
Toledo Edison Co.
BBB-
Baa3
-
BBB
Baa1
-
-
-
-
stable
stable
-
Trans-Allegheny Interstate Line Co.
BBB-
A3
-
-
-
-
BBB-
A3
-
stable
stable
-
West Penn Power Co.
BBB-
Baa1
-
BBB+
A2
-
-
-
-
stable
stable
-
On March 24, 2015, Moody's Investors Service affirmed JCP&L's Baa2 rating and revised its rating outlook to "stable" from "negative".
FirstEnergy FactBook
Published May 1, 2015
157
Financial – 2015 Financial Plan
Committed to maintain investment grade metrics at each business unit and
improve metrics at FE Corp. over time consistent with business profile
■ Focus on FE Transmission growth
– Long-term financings to support growth*
■ Target positive cash flow in 2015 at CES
– Refinancing of maturing debt*
– Focus on cost control in low power price environment
■ Continued focus on strengthening FE Utilities balance sheets
– Refinancing of maturing debt at certain utilities*
– Reduce short-term borrowings through refinancings*
■ Issue equity through stock investment/employee benefit plans, as
available – program targets ~$100M**
*Subject to market and other conditions. ** Varies based on participation and market conditions
FirstEnergy FactBook
Published May 1, 2015
158
81
FirstEnergy FactBook
Published May 1, 2015
Financial – 2014 Financial Accomplishments
■ Revised annual dividend level of $1.44 per share
– Dividend level aligned with FE’s targeted business mix (80+% regulated, <20% competitive)
– Fully supported by earnings and cash flows from regulated businesses
– Provides balance sheet capacity to invest in transmission reliability projects
■ Focus on FE Transmission growth
– Issued long-term debt to support transmission reliability program
$1B at FET HoldCo
– $400M at ATSI
– $550M at TrAIL ($450M refinanced)
–
■ Focus on strengthening FES/AE Supply balance sheets
– $394M sale of hydro assets completed on February 12, 2014
– Refinanced certain debt at FEGENCO and FENUGENCO
■ Focus on strengthening FE Utilities balance sheets
– Refinanced maturing debt at certain utilities
– Reduced short-term borrowings through refinancings
■ Improved liquidity by restructuring existing credit facilities
– Extended maturity of facilities by one year to March 2019
– Upsized FE Corp/FEU facility to $3.5B while reducing FES/AE Supply facility to $1.5B
– FE Corp. entered into a new $1B 5-year term loan
■ Issued equity – ~$83M in 2014 through stock investment/employee benefit plans
As of December 31, 2014
FirstEnergy FactBook
Published May 1, 2015
159
Financial – Credit Providers
32 financial institutions provide ~$7.6B aggregate credit commitment
($ Millions)
Revolving Credit Facilities
Term Loans
$6,000
1,200
SUB-TOTAL
Letters of Credit (LOC)
Vehicle Leases
Sale Leaseback LOC
TOTAL
$7,200
184
208
20
$7,612
Bank of America
Bank of New York Mellon
Bank of Nova Scotia
Barclays Bank
BBVA
BNP Paribas
CIBC
Citibank
Citizens Bank
CoBank
Credit Agricole
Credit Suisse
Fifth Third Bank
First National Bank
G.E. Capital
Goldman Sachs
Huntington National Bank
JP Morgan Chase
Keybank
Mizuho
Morgan Stanley
National Cooperative Services
PNC
Regions Bank
Royal Bank of Canada
Royal Bank of Scotland
Santander
Sumitomo Mitsui
TD Bank
Union Bank/Bank of Tokyo Mitsubishi
US Bank
Wells Fargo
As of March 31, 2015
FirstEnergy FactBook
Published May 1, 2015
160
82
FirstEnergy FactBook
Published May 1, 2015
Financial – Operating Earnings1 by Segment
1
Operating EPS – Basic
2014A
2015 Guidance
Regulated Distribution
$1.93
$1.74 - $1.90
Regulated
Transmission
0.54
0.63 - 0.67
$2.47
$2.37 – $2.57
0.23
0.45 – 0.55
Corporate / Other
(0.14)
(0.42)
FirstEnergy
Consolidated
$2.56
$2.40 - $2.70
Sub-total
Competitive Energy
Services
1See
GAAP to Operating earnings reconciliation on slides 168 and 169
Published May 1, 2015
FirstEnergy FactBook
161
FE Consolidated – 2014 to 2015 Earnings
0.12 $3.50
0.30
0.44 $3.00
Transmission
Revenues
$2.50
$2.56
0.04 0.03 Gross
Distribution Receipts
Sales
Taxes
PA/WV/NJ
Rate Cases
0.30
0.22
Effective
Tax
Rate Depreciation
/ Property
Taxes
0.14 0.14 O&M
0.07 0.05
0.02 Net
Financing Investment Pension/
Shares
Income
Costs
OPEB Outstanding/
Other
CES
Commodity
Margin
$2.55
$2.00
$1.50
$1.00
$0.50
$0.00
2014 Actual
2014
Operating Earnings
Results
Drivers and assumptions published February 17, 2015. Operating earnings guidance reaffirmed May 1, 2015.
FirstEnergy FactBook
20152015 Guidance
Operating
Earnings Guidance
Midpoint
Published May 1, 2015
162
83
FirstEnergy FactBook
Published May 1, 2015
Regulated Distribution – 2014 to 2015
$/share
$1.95
Earnings Drivers
$ 1.93
$1.90
Distribution Sales
$0.04
PA Settlement
$0.18
WV Settlement Order
$1.85
$1.80
$1.75
Assumptions
$0.02
NJ Storm Amortization
($0.08)
Effective Tax Rate
($0.05)
O&M
($0.08)
Pension & OPEB
($0.03)
Depreciation and Property Tax
($0.08)
Investment Income
($0.01)
Net Financing Costs
($0.01)
Shares Outstanding
($0.01)
2014 Operating
Earnings Results
$1.82
2015 Operating Earnings
Guidance Midpoint
■ Distribution Sales – Forecasted sales of ~151M MWH in 2015 versus
149.5M MWH in 2014
■ PA – $120M pre-tax earnings benefit effective May 2015 per settlements;
annual pre-tax earnings benefit of $205M
■ WV – Pre-tax earnings impact of $13M per rate case settlement order,
effective February 25, 2015
■ NJ – Assumes 2015 revenues neutral to 2014; ($0.08) for 2011 & 2012
storm amortization, effective March 1, 2015
■ Effective Tax Rate – 35.2% in 2014 vs. 36.9% in 2015
■ O&M – Higher Distribution O&M expenses ($0.05), primarily in PA, and
higher generation O&M for regulated plants ($0.03)
■ Pension & OPEB – Higher expense due to lower amortization of prior
service credits along with annual updates to actuarial assumptions
■ Depreciation & Property Tax – Results primarily from higher rate base
■ Investment Income – Lower interest and dividend income
■ Net Financing Costs – Related to new debt issuances, partially offset
by lower short-term interest costs
■ Shares Outstanding – ~420M shares in 2014 to ~422M in 2015
Drivers and assumptions published February 17, 2015. Operating earnings guidance reaffirmed May 1, 2015.
Published May 1, 2015
FirstEnergy FactBook
163
Regulated Transmission – 2014 to 2015
$/share
$0.66
$0.65
$0.64
$0.62
Earnings Drivers
$0.60
Transmission Revenues
$0.30
$0.58
Effective Tax Rate
$0.56
$0.54
$0.54
($0.02)
Net Financing Costs
($0.06)
Depreciation/Property Tax
($0.11)
$0.52
$0.50
2014 Operating
Earnings Results
2015 Operating Earnings
Guidance Midpoint
Assumptions
■ Transmission Revenue – Assumes impact of ATSI forward looking rate filing with 1/1/15 effective date and higher rate base
at ATSI / TrAILCo
■ Effective Tax Rate – 35.2% in 2014 vs. 36.9% in 2015
■ Net Financing Costs – Reflects full year impact of debt issuances at FET Hold Co ($1,000M) and ATSI ($400M) and lower
average CWIP balance resulting in decreased AFUDC-equity earnings
■ Depreciation / Property Tax – Increased expenses resulting from higher asset base
Drivers and assumptions published February 17, 2015. Operating earnings guidance reaffirmed May 1, 2015.
FirstEnergy FactBook
Published May 1, 2015
164
84
FirstEnergy FactBook
Published May 1, 2015
Competitive Energy Services – 2014 to 2015
$/share
$0.70
Earnings Drivers
$0.60
$0.50
$0.40
$0.30
$0.23
$0.20
Commodity Margin
$0.44
Gross Receipts Taxes
$0.03
Net Financing Costs
($0.02)
Effective Tax Rate
($0.01)
Investment Income
($0.06)
Depreciation
($0.03)
Pension & OPEB
($0.02)
O&M
($0.06)
$0.50
$0.10
2014 Operating
Earnings Results
2015 Operating
Earnings Guidance Midpoint
Assumptions
■ Commodity Margin
– Lower spot purchased power
– Higher capacity revenue from increased prices
– Lower delivery expense costs
– Lower fuel rates from fossil and nuclear
■ Gross Receipts Taxes – Lower gross receipts taxes due to
lower retail sales volumes
■ Net Financing Costs– Refinancing of PCRB’s
■ Effective Tax Rate – 35.2% in 2014 vs. 36.9% in 2015
■ Investment Income – Lower other income from realized gains in 2014
■ Depreciation – Increased expenses due to full year of DB steam generator and
higher asset base
■ Pension & OPEB- Higher expense due to lower amortization of prior service
credits along with updates to actuarial assumptions
■ O&M – 3 nuclear outages in 2015 vs 2 in 2014
Drivers and assumptions published February 17, 2015. Operating earnings guidance reaffirmed May 1, 2015.
Published May 1, 2015
FirstEnergy FactBook
165
Corporate / Other – 2014 to 2015
$/share
($0.10)
ETR Drivers
($0.14)
IRS Accounting Method
Change
($0.20)
($0.30)
Earnings Drivers
Effective Tax Rate
($0.40)
($0.08)
Resolution of State Tax
Positions
($0.08)
Tax Basis Adjustments
($0.06)
($0.22)
Net Financing Costs
($0.05)
Other
($0.01)
($0.42)
($0.50)
2014 Operating
Earnings Results
2015 Operating
Earnings Guidance
Assumptions
■ Effective Tax Rate – 2014 consolidated ETR of 29% vs. 37% - 38% in 2015
■ Net Financing Costs
– Increased rate on $1B in variable rate debt in March 2014
– Higher short-term interest expense
Drivers and assumptions published February 17, 2015. Operating earnings guidance reaffirmed May 1, 2015.
FirstEnergy FactBook
Published May 1, 2015
166
85
FirstEnergy FactBook
Published May 1, 2015
2016 vs. 2015 Earnings Drivers
Regulated Distribution
Competitive Energy Services
Distribution Revenue
Commodity Margin
O&M
Sales Revenue
Depreciation
Capacity Revenue
Interest
Capacity Expense
Effective Tax Rate
Purchased Power
Fuel
Regulated Transmission
O&M
Transmission Revenue
General Taxes
Depreciation
Depreciation
General Tax
Effective Tax Rate
Interest
Effective Tax Rate
167
Published May 1, 2015
FirstEnergy FactBook
Financial – 2015 GAAP to Operating Earnings Reconciliation
1
FirstEnergy
Consolidated
Regulated
Distribution
Regulated
Transmission
Competitive
Energy
Services
Corporate/
Other
2015F
2015F
2015F
2015F
2015F
$915M - $1,040M
$705M - $775M
$265M - $280M
$120M - $160M
($175M)
$2.17 - $2.47
$1.67 - $1.83
$0.63 - $0.67
$0.29 - $0.39
($0.42)
Regulatory Charges
$0.07
$0.07
-
-
-
Trust Securities Impairment
$0.01
-
-
$0.01
-
Plant Deactivation Costs
$0.02
-
-
$0.02
-
(In Millions, except per share amounts)
Net Income (Loss) – GAAP
Basic EPS
(average shares outstanding 422M)
Excluding Special Items2:
Merger Accounting – Commodity Contracts
$0.07
-
-
$0.07
-
Non-core Asset Sales/Impairments
$0.02
-
-
$0.02
-
Retail Repositioning Charges
$0.04
-
-
$0.04
-
$0.23
$0.07
$0.00
$0.16
$0.00
$2.40 - $2.70
$1.74 - $1.90
$0.63 - $0.67
$0.45 - $0.55
($0.42)
Total Special Items2
Basic EPS – Operating (Non-GAAP)
(average shares outstanding 422M)
1Operating
2Per
earnings exclude special items as described in the reconciliation table above and is a non-GAAP financial measure
share amounts for the special items above are based on the after tax effect of each item divided by the weighted average shares outstanding for the period
FirstEnergy FactBook
Published May 1, 2015
168
86
FirstEnergy FactBook
Published May 1, 2015
Financial – 2014 GAAP to Operating Earnings Reconciliation
1
FirstEnergy
Consolidated
Regulated
Distribution
Regulated
Transmission
Competitive
Energy
Services
Corporate/
Other
(In Millions, except per share amounts)
2014A
2014A
2014A
2014A
2014A
Net Income (Loss) – GAAP
$299M
$465M
$223M
($337M)
($52M)
Basic EPS
(average shares outstanding 420M)
$0.71
$1.11
$0.53
($0.80)
($0.13)
Pension/OPEB actuarial assumptions
1.23
0.74
0.01
0.48
–
Other
0.11
–
–
0.11
–
Excluding Special Items2:
Mark-to-market Adjustments
Plant Deactivation Costs
0.34
–
–
0.34
–
Trust Securities Impairment
0.06
0.01
–
0.05
–
Regulatory Charges
0.08
0.07
–
0.01
–
Litigation Resolution
(0.01)
–
–
–
(0.01)
Loss on Debt Redemptions
0.01
–
–
0.01
–
Merger Accounting – Commodity Contracts
0.07
–
–
0.07
–
(0.15)
–
–
(0.15)
–
0.11
–
–
0.11
–
Total Special Items2
$1.85
$0.82
$0.01
$1.03
($0.01)
Basic EPS – Operating (Non-GAAP)
(average shares outstanding 420M)
$2.56
$1.93
$0.54
$0.23
($0.14)
Non-core Asset Sales/Impairments
Retail Repositioning Charges
1Operating
earnings exclude special items as described in the reconciliation table above and is a non-GAAP financial measure
2Per share amounts for the special items above are based on the after tax effect of each item divided by the weighted average shares outstanding for the period
169
Published May 1, 2015
FirstEnergy FactBook
Financial – 2014A Capital Expenditures
Capital Expenditures
($ Millions)
Baseline Capital
Formula Rate Recoverable
Regulated
Distribution
Regulated
Transmission
CES1
Corporate/
Other
FirstEnergy
Consolidated2
$869
$192
$436
$84
$1,581
413
1,177
–
–
1,590
336
Major Projects
Generation Projects
MATS
JCP&L LITE
Storms
Total
1
2
–
–
336
–
31
–
20
–
51
4
52
–
–
56
69
2
–
–
71
$1,386
$1,423
$792
$84
$3,685
Excludes nuclear fuel of $233M
Total includes $387M associated with the capital component of the Pension and OPEB mark-to-market adjustment.
FirstEnergy FactBook
Published May 1, 2015
170
87
FirstEnergy FactBook
Published May 1, 2015
Financial – 2015F Capital Expenditures
Capital Expenditures
($ Millions)
Baseline Capital
Regulated
Distribution
Regulated
Transmission
CES1
Corporate/
Other
FirstEnergy
Consolidated
$720
$125
$440
$115
$1,400
375
805
–
–
1,180
180
Formula Rate Recoverable
Major Projects
Generation Projects
MATS
JCP&L LITE
Storms
Total
1
–
–
180
–
65
–
30
–
95
5
40
–
–
45
40
–
–
–
40
$1,205
$970
$650
$115
$2,940
Excludes nuclear fuel of $205M
FirstEnergy FactBook
Published May 1, 2015
171
Financial – Funds from Operations Reconciliation
FirstEnergy Consolidated ($ Millions)
Net Income – GAAP
2014A
$299
Depreciation
1,220
Amortization of Regulatory Assets, net
12
Nuclear Fuel Amortization(1)
220
Deferred Taxes and ITC(2)
107
Deferred Purchased Power and Other Costs(3)
(115)
Pension and OPEB MTM
835
NDT Impairments and Gains(4)
(27)
Loss on Debt Redemptions
8
Gain on Asset Sale, pre-tax
(142)
76
Other(5)
Funds from Operations (FFO)
$2,493
1 Included
in fuel expense
Combined Notes to Consolidated Financial Statements - Note 5,Taxes. Includes deferred taxes from continuing and discontinued operations
in consolidated statement of cash flows
4 Includes investment impairments and gain on investment securities held in trust in consolidated statement of cash flows
5 Primarily includes securitized debt principal payments and non-cash items such as unrealized gain and losses on derivative contracts and AFUDC
2 See
3 Included
FirstEnergy FactBook
Published May 1, 2015
172
88
FirstEnergy FactBook
Published May 1, 2015
2014 Free Cash Flow
FirstEnergy
Consolidated
($ Millions)
Funds From Operations (FFO)1
Capital Expenditures2
Nuclear Fuel
Cash Before Other Items
Hydro Asset Sales
Collateral
Working Capital/Other
Cash Before Dividends and Equity
Dividends @ $1.44/share
Equity (SIP and other employee benefit plans)
$2,493
(3,298)
(233)
($1,038)
394
(54)
4
($694)
(604)
83
Free Cash Flow 3
($1,215)
1 Non-GAAP
2
3
measure; See GAAP to FFO reconciliation on slide 172
Excludes capital component of Pension/OPEB mark-to-market adjustment
Excludes cash items related to financing activity
Published May 1, 2015
FirstEnergy FactBook
173
Financial – Funds from Operations Reconciliation
FirstEnergy Consolidated ($ Millions)
Net Income – GAAP
Depreciation
1,345
Amortization of Regulatory Assets, net
317
Nuclear Fuel Amortization
215
Deferred Taxes and ITC
510
Deferred Purchased Power and Other Costs
(40)
Retirement Benefits
25
(122) – (47)
Other(1)
Funds from Operations (FFO)
1 Primarily
2015F
$915 - $1,040
$3,165 - $3,365
includes securitized debt principal payments and non-cash items such as unrealized gain and losses on derivative contracts and AFUDC
FirstEnergy FactBook
Published May 1, 2015
174
89
FirstEnergy FactBook
Published May 1, 2015
2015F Free Cash Flow
($ Millions)
FirstEnergy
Consolidated
Funds From Operations (FFO)1
Capital Expenditures
Nuclear Fuel
Cash Before Other Items
Pension Contribution
Working Capital/Other
Cash Before Dividends and Equity
Dividends @ $1.44/share
Equity (SIP and other employee benefit plans)
$3,165 - $3,365
(2,942)
(205)
$18 - $218
(143)
125
$0 - $200
(610)
105
Free Cash Flow 2
($505) - ($305)
1 Non-GAAP
2
measure; See GAAP to FFO reconciliation on slide 174. Amount shown reflects the midpoint
Excludes cash items related to financing activity
Published May 1, 2015
FirstEnergy FactBook
175
Financial – Qualified Pension Status Overview
2013
2014
2015
Assumptions
Expected Return on Assets
7.75%
7.75%
7.75%
Previous Year-End Discount Rate
4.25%
5.00%
4.25%
Plan Assets
$6,171
$5,824
ABO Liability
$7,554
$8,422
Pension Plan ($ Millions)
Assumptions* - Pension Costs
Pension Funding (Year End)
ABO Funding Ratio
82%
69%
($ Millions)
2013
2014
2015F
$–
$–
$ 143
Contributions during the year
■ Projected Benefit Obligation (PBO) Liability as of December 2014 was $8,889M
– A 25 bps increase in the discount rate decreases the PBO liability by ~$220-250M
■ At December 31, 2014, the annual Pension and OPEB mark-to-market adjustment was $1.2B of
which $835M, or $1.23 per share, was recorded in operating expenses and $387M was included
as a capital cost. The mark-to-market adjustment primarily reflects a discount rate of 4.25%
(4.00% on OPEB), lower mortality rates, and other actuarial changes.
* Assumptions relate to net periodic pension costs as opposed to the pension benefit obligation. Year-end liabilities are valued based on the end-of-year discount rate.
FirstEnergy FactBook
Published May 1, 2015
176
90
FirstEnergy FactBook
Published May 1, 2015
Financial – Credit Metrics Calculations
FFO Calculation
FFO Interest Coverage
Net Income
Adjustments for non-cash items:
Depreciation, amortization (incl. nuclear fuel, Pension/OPEB MTM
adjustment and lease amortization), and deferral of regulatory assets
Deferred purchased power and other costs
Deferred income taxes and investment tax credits
Investment impairments
Retirement benefits
Loss on debt redemptions
Gain on Asset Sale
Other
=
FFO + Adjusted Interest
Adjusted Interest
Adjusted Interest:
+ Interest Expense (before AFUDC)
+ Interest portion of leases
– Securitization bond interest expense
= Adjusted Interest
= Funds from Operations (FFO)
Debt / Capitalization Ratio
Rating Agency View
Covenant View
Debt:
Debt:
Long-term debt
Long-term debt
+ Short-term borrowings
+ Short-term borrowings
+ Operating lease debt equivalent*
– Securitization debt
+ Post-retirement benefit
+ Guarantees of Indebtedness
obligations**
+ Reimbursement Obligations
+ Other debt
– Securitization debt
= Adjusted Debt
= Adjusted Debt
Capitalization:
Capitalization:
+ Adjusted debt
+ Adjusted Debt
+ Total equity
+ Total Equity
– Accumulated OCI
+ Non-cash charges***
= Adjusted Capitalization
= Adjusted Capitalization
FFO-to-Debt Ratio
=
FFO
Adjusted Debt
Adjusted debt:
+ Short-term borrowings
+ Long-term debt
+ Operating lease debt equivalent*
+ Post-retirement benefit obligations**
+ Other debt
– Securitization debt
= Adjusted Debt
* Net Present Value of future lease payments using discount rate of 7%
** After-tax unfunded Pension/OPEB obligation
*** Includes historical (2012-2014) and forward-looking non-cash charges
FirstEnergy FactBook
Published May 1, 2015
177
FirstEnergy Investor Relations Contacts
Irene M. Prezelj, Vice President
[email protected]
330-384-3859
Meghan G. Beringer, Director
[email protected]
330-384-5832
Rey Y. Jimenez, Jr., Manager
[email protected]
330-761-4239
Gina E. Caskey, Manager
[email protected]
330-384-3841
For our e-mail distribution list, please contact:
Linda M. Nemeth, Executive Assistant to Vice President
[email protected]
330-384-2509
Shareholder Inquiries:
Shareholder Services (American Stock Transfer and Trust Company, LLC)
[email protected]
1-800-736-3402
FirstEnergy FactBook
Published May 1, 2015
178
91